Method of solvent recovery from a solvent based heavy oil extraction process

ABSTRACT

The present disclosure relates to production of a bitumen product from a subterranean reservoir with improved processes for solvent recovery at end of production or near end of production (i.e., “late life”) of heavy oil from a solvent-based heavy oil extraction process. The process include converting at least some of the wells in the subterranean reservoir, and injecting gas phase dilution agent into the reservoir, converting at least a portion of the liquid solvent to a gas phase, and recovering, in the vapor phase, at least a portion of the solvent remaining in the reservoir.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority from Canadian patent application2,974,711 filed 27 Jul. 2017 entitled METHOD OF SOLVENT RECOVERY FROM ASOLVENT BASED HEAVY OIL EXTRACTION PROCESS, the entirety of which isincorporated by reference herein.

BACKGROUND Field of Disclosure

The present disclosure relates to production of a bitumen product from asubterranean reservoir with improved processes for solvent recovery atend of production or near end of production of heavy oil from asolvent-based heavy oil extraction process.

Description of Related Art

This section is intended to introduce various aspects of the art. Thisdiscussion is believed to facilitate a better understanding ofparticular aspects of the present techniques. Accordingly, it should beunderstood that this section should be read in this light, and notnecessarily as admissions of prior art.

Modern society is greatly dependent on the use of hydrocarbon resourcesfor fuels and chemical feedstocks. Subterranean rock formations that canbe termed “reservoirs” may contain resources such as hydrocarbons thatcan be recovered. Removing hydrocarbons from the subterranean reservoirsdepends on numerous physical properties of the subterranean rockformations, such as the permeability of the rock containing thehydrocarbons, the ability of the hydrocarbons to flow through thesubterranean rock formations, and the proportion of hydrocarbonspresent, among other things.

Easily produced sources of hydrocarbons are dwindling, leaving lessconventional sources to satisfy future needs. As the costs ofhydrocarbons increase, less conventional sources become more economical.One example of less conventional sources becoming more economical isthat of oil sand production. The hydrocarbons produced from lessconventional sources may have relatively high viscosities, for example,ranging from 1000 centipoise (cP) to 20 million cP, with AmericanPetroleum Institute (API) densities ranging from 8 degree (°) API, orlower densities, up to 20° API, or higher densities. The hydrocarbonsrecovered from less conventional sources may include heavy oil. However,the hydrocarbons produced from the less conventional sources may bedifficult to recover using conventional techniques. For example, theheavy oil may be sufficiently viscous that economical production of theheavy oil from a subterranean formation (also referred to as a“subterranean reservoir” herein) is precluded.

Several conventional processes for the extraction of heavy oils, such asbut not limited to thermal extraction processes, have been utilized todecrease the viscosity of the heavy oil. Decreasing the viscosity of theheavy oil may decrease a resistance of the heavy oil to flow and/orpermit production of the heavy oil from the subterranean reservoir bypiping, flowing, and/or pumping the heavy oil from the subterraneanreservoir. While each of these extraction processes may be effectiveunder certain conditions, each possess inherent limitations.

One of the conventional extraction processes utilizes steam injection.The steam injection may be utilized to heat the heavy oil to decreasethe viscosity of the heavy oil. Water and/or steam may represent aneffective heat transfer medium, but the pressure required to producesaturated steam at a desired temperature may limit the applicability ofsteam injection to high pressure operation and/or require a large amountof energy to heat the steam.

Another group of the conventional extraction processes utilizes coldand/or heated solvents. Cold and/or heated solvents may be injected intoa subterranean reservoir as liquids and/or vapors to decrease theviscosity of heavy oil present within the subterranean reservoir. Theinjected solvent may dissolve the heavy oil, dilute the heavy oil,and/or transfer thermal energy to the heavy oil.

Some processes combine both steam injection and solvent injection toobtain improved extraction from both the use of the heat of the steam aswell as the solvency of the heavy oils in the injected solvent todecrease the viscosity of the heavy oil. While these processes using acombination of steam and solvent are effective, they are also hamperedby the associated capital and maintenance costs of having to produce andsupply both steam and solvent to the process.

The solvent based extraction processes (which include the use of aninjected solvent alone or with another fluid such as steam as describedabove) tend to have the benefit of improving the overall extraction ofheavy oil from a subterranean reservoir or formation. However, asignificant cost in these solvent based processes is the cost of thesolvents themselves which are difficult to recover from the subterraneanreservoir during heavy oil recovery, as well as after the well hasneared or is at the end of its economically useful life. At the end (ornear the end) of the reservoir's production, typically a significantvolume of solvent, worth millions of dollars of solvent value, that hasbeen injected to assist in the extraction of the heavy oil may beremaining in the reservoir.

Conventional process for solvent recovery at near end of life ofreservoirs in solvent based extraction processes generally involvesreducing or cutting off the solvent injection and utilizing steaminjected through an upper injection well as a mechanism to recover thesolvent with bitumen from the reservoir. The injected steam evaporatesthe retained solvent and condenses it at the edge of the chamber whereit gravity drains to a lower production well along with extractedbitumen. The steam injection process thus recovers the solvent as aliquid through the process of gravity drainage. This technique canresult in very slow and inefficient solvent recovery. Additionally, theproduction of the large amounts of steam required is very energyintensive as well as requiring large amounts of water, which not onlyneeds to be significantly treated (e.g., water softening, pH control,etc.) in order to produce the steam but requires a large amount of waterwhich may not be readily available in a solvent-based extractionprocesses location. Even more of an impediment to conventionalsteam-based solvent recovery processes is typically that thesolvent-based extraction processes require little or essentially nosteam for use in injection process. As such, the solvent-basedextraction processes typically have significantly undersized steamcapacity (if any) to perform the steam flooding recovery processes.Therefore, extensive capital and construction is required to employlarge steam generation systems at these sites to employ theseconventional steam injection based solvent recovery processes toresources previously utilizing solvent-based heavy oil recoveryprocesses.

Improved processes that can recover the remaining solvent from asubterranean reservoir can significantly reduce the overall cost ofproducing heavy oil from solvent based extraction processes.Additionally, removal of remaining solvents in a subterranean reservoirmay provide environmental improvements by reducing the amount ofremaining solvents in a shut-in reservoir from a solvent based heavy oilrecovery process. Therefore, a need exists in the industry for improvedtechnology, including technology that improves the recovery of solventsremaining in a subterranean reservoir at the end (or near the end, i.e.,“late life”) of the reservoir's production stage.

SUMMARY

It is an object of the present disclosure to provide systems and methodsfor improving the recovery of solvents from a subterranean reservoirremaining in the reservoir at the end (or near the end, i.e. “latelife”) of the production stage of a reservoir that has been subjected toa solvent based heavy oil extraction process.

An embodiment disclosed herein includes a process for the recovery of asolvent from a subterranean reservoir containing a solvent and a heavyoil, the process comprising:

a) recovering a heavy oil from a subterranean reservoir utilizing asolvent-assisted gravity drainage process wherein a portion of a solventfrom the solvent-assisted gravity drainage process remains located inthe subterranean reservoir;

b) injecting a gas phase dilution agent into the subterranean reservoir;

c) contacting at least a portion of the gas phase dilution agent withthe solvent;

d) vaporizing at least a portion of the solvent that is in the liquidphase to produce a vaporized solvent; and

e) extracting at least a portion of the gas phase dilution agent and thevaporized solvent from the subterranean reservoir.

In a preferred embodiment, the gas phase dilution agent comprises anon-condensable gas which remains in vapor phase at pressure andtemperature of the subterranean reservoir.

Another embodiment disclosed herein includes the process wherein thesolvent-assisted gravity drainage process step comprises a well pairlocated in the subterranean reservoir, wherein the well pair iscomprised of at least one injection well and at least one productionwell and further wherein the at least one injection well is converted toan NCG injection well prior to, or in conjunction with, step b), andinjecting the gas phase dilution agent into the subterranean reservoirvia the NCG injection well.

Another embodiment disclosed herein includes the process wherein thesolvent-assisted gravity drainage process step comprises at least twowell pairs located in the subterranean reservoir, wherein each well pairis comprised of an injection well and a production well in step a),prior to, or in conjunction with, step b):

-   -   converting at least one of the injection wells or production        wells to an NCG injection well; and    -   converting at least one of the injection wells or production        wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection well; and at leasta portion of the gas phase dilution agent and the vaporized solvent isextracted from the subterranean reservoir via the NCG/vaporized solventproduction well.

Another embodiment disclosed herein includes the process wherein thesolvent-assisted gravity drainage process step comprises at least threewell pairs located in the subterranean reservoir, wherein each well pairis comprised of an injection well and a production well in step a),prior to, or in conjunction with, step b):

-   -   converting at least two of the injection wells to NCG injection        wells; and    -   converting at least one of the injection wells or production        wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection wells; and atleast a portion of the gas phase dilution agent and the vaporizedsolvent is extracted from the subterranean reservoir via theNCG/vaporized solvent production well.

Another embodiment disclosed herein includes the process wherein thesolvent-assisted gravity drainage process step comprises at least threewell pairs located in the subterranean reservoir, wherein each well pairis comprised of an injection well and a production well in step a),prior to, or in conjunction with, step b):

-   -   converting at least one of the injection wells to NCG injection        wells; and    -   converting at least two of the injection wells or production        wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection well; and at leasta portion of the gas phase dilution agent and the vaporized solvent isextracted from the subterranean reservoir via the NCG/vaporized solventproduction wells.

Another embodiment disclosed herein includes the process wherein thesolvent-assisted gravity drainage process step comprises at least twowell pairs located in the subterranean reservoir, wherein each well pairis comprised of an injection well and a production well in step a),prior to, or in conjunction with, step b):

-   -   converting an existing infill well or installing a new infill        well in the subterranean reservoir located in a horizontal        direction between the two well pairs for use as an NCG/vaporized        solvent production well; and    -   converting the two injection wells or the two production wells        to NCG injection wells;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection well; and at leasta portion of the gas phase dilution agent and the vaporized solvent isextracted from the subterranean reservoir via the NCG/vaporized solventproduction well.

Another embodiment disclosed herein includes the process wherein thesolvent-assisted gravity drainage process step comprises at least twowell pairs located in the subterranean reservoir, wherein each well pairis comprised of an injection well and a production well in step a),prior to, or in conjunction with, step b):

-   -   converting an existing infill well or installing a new infill        well in the subterranean reservoir located in a horizontal        direction between the two well pairs for use as an NCG injection        well; and    -   converting the two injection wells or the two production wells        to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection well; and at leasta portion of the gas phase dilution agent and the vaporized solvent isextracted from the subterranean reservoir via the NCG/vaporized solventproduction wells.

Another embodiment disclosed herein includes the process wherein thesolvent-assisted gravity drainage process step comprises at least onewell pair located in the subterranean reservoir, wherein each well pairis comprised of an injection well and a production well in step a), andprior to, or in conjunction with, step b):

-   -   converting at least one of the injection well or the production        well in each well pair to a NCG/vaporized solvent production        well;    -   injecting the gas phase dilution agent into the top of the        subterranean reservoir or into an existing top zone of the        subterranean reservoir;    -   creating a gas cap in the subterranean reservoir comprising the        gas phase dilution agent; and    -   expanding the gas cap downward into the subterranean reservoir        to at least a point wherein gas cap is in contact with the        NCG/vaporized solvent production wells;

wherein in step e), the at least a portion of the gas phase dilutionagent and the vaporized solvent is extracted from the subterraneanreservoir via the NCG/vaporized solvent production well.

Another embodiment disclosed herein includes a system for the recoveryof a solvent from a subterranean reservoir containing a solvent and aheavy oil, the system comprising:

-   -   a subterranean reservoir containing an existing solvent        comprising a liquid phase and a heavy oil;    -   a first injector fluidly connected to the subterranean        reservoir, wherein the injector is located to inject a gas phase        dilution agent into the subterranean reservoir, so as to contact        at least a portion of the gas phase dilution agent with the        existing solvent and vaporize at least a portion of the existing        solvent to produce a vaporized solvent; and    -   a first NCG/vaporized solvent production well located within the        subterranean reservoir and fluidly connected to the first        injector;

wherein the first NCG/vaporized solvent production well is configured torecover a portion of the gas phase dilution agent and a portion of thevaporized solvent.

The foregoing has broadly outlined the features of the presentdisclosure so that the detailed description that follows may be betterunderstood. Additional features will also be described herein.

DESCRIPTION OF THE DRAWINGS

These and other features, aspects and advantages of the presentdisclosure will become apparent from the following description and theaccompanying drawings, which are briefly discussed below.

FIG. 1 illustrates the solvent stripping mechanism due to dilution andpartial pressure reduction by non-condensable gases.

FIG. 2 illustrates the solvent vaporization due to dilution and partialpressure reduction by non-condensable gases.

FIG. 3 is a simplistic diagram of a single well pair configuration in asubterranean reservoir as used in an embodiment of the invention herein.

FIGS. 4A-4E illustrate reservoir well configurations and flow patternsfor various gas sweep embodiments of the present invention.

FIG. 5 is a simplified illustration of the well configuration utilizedin modeling embodiments of the gas sweep configurations of the presentinvention.

FIG. 6A is a graph of the solvent production rate as a function of timefor the steam injection model (SAGD mode) of an embodiment of thepresent invention for a single well pair configuration.

FIG. 6B is a graph of the solvent production rate as a function of timefor the NCG injection model of an embodiment of the present inventionfor a single well pair configuration.

FIG. 6C is a graph of the solvent production rate as a function of timefor the inter-well pair NCG flood model of an embodiment of the presentinvention for a multiple well pair configuration using a gas flood/sweepconfiguration.

FIG. 7 is a graph comparing the solvent recovery (in percentage of totalsolvent) for different solvent recovery methods. It includes the steamonly (switch to SAGD), NCG injection for a single well pairconfiguration, and an inter-well pair NCG flood case of the presentinvention for a multiple well pair configuration using a gas flood/sweepconfiguration.

FIG. 8 illustrates a reservoir well configuration and flow patterns fora gas cap expansion embodiment of the present invention.

FIG. 9 is a graph comparing the solvent recovery (in percentage of totalsolvent) for the present invention for a multiple well pairconfiguration using the gas cap expansion configuration and inter-wellpair NCG flood configuration.

FIG. 10 is a graph comparing the solvent recovery (in percentage oftotal solvent) for two models of the present invention using the gasflood/sweep configuration and the gas cap expansion configuration, incomparison with a steam injection only (SAGD) solvent recovery model ofthe prior art for a multiple well pair configuration.

DETAILED DESCRIPTION

For the purpose of promoting an understanding of the principles of thedisclosure, reference will now be made to the features illustrated inthe drawings and specific language will be used to describe the same. Itwill nevertheless be understood that no limitation of the scope of thedisclosure is thereby intended. Any alterations and furthermodifications, and any further applications of the principles of thedisclosure as described herein, are contemplated as would normally occurto one skilled in the art to which the disclosure relates. It will beapparent to those skilled in the relevant art that some features thatare not relevant to the present disclosure may not be shown in thedrawings for the sake of clarity.

At the outset, for ease of reference, certain terms used in thisapplication and their meanings as used in this context are set forth. Tothe extent a term used herein is not defined below, it should be giventhe broadest definition persons in the pertinent art have given thatterm as reflected in at least one printed publication of issued patent.Further, the present techniques are not limited by the usage of theterms shown below, as all equivalents, synonyms, new developments, andterms or processes that serve the same or a similar purpose areconsidered to be within the scope of the present disclosure.

A “hydrocarbon” is an organic compound that primarily includes theelements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals,or any number of other elements may be present in small amounts.Hydrocarbons generally refer to components found in heavy oil or in oilsands. However, the techniques described herein are not limited to heavyoils, but may also be used with any number of other subterraneanreservoirs. Hydrocarbon compounds may be aliphatic or aromatic, and maybe straight chained, branched, or partially or fully cyclic.

“Bitumen” is a naturally occurring heavy oil material. Generally, it isthe hydrocarbon component found in oil sands. Bitumen can vary incomposition depending upon the degree of loss of more volatilecomponents. It can vary from a very viscous, tar-like, semi-solidmaterial to solid forms. The hydrocarbon types found in bitumen caninclude aliphatics, aromatics, resins, and asphaltenes. A typicalbitumen might be composed of:

19 weight % (wt. %) aliphatics (which can range from 5 wt. %-30 wt. %,or higher);

19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %, or higher);

30 wt. % aromatics (which can range from 15 wt. %-50 wt. %, or higher);

32 wt. % resins (which can range from 15 wt. %-50 wt. %, or higher);

and some amount of sulfur (which can range in excess of 7 wt. %).

The percentage of the hydrocarbon types found in bitumen can vary. Inaddition, bitumen can contain some water and nitrogen compounds rangingfrom less than 0.4 wt. % to in excess of 0.7 wt. %. The metals content,while small, may be removed to avoid contamination of synthetic crudeoil. Nickel can vary from less than 75 ppm (parts per million) to morethan 200 ppm. Vanadium can range from less than 200 ppm to more than 500ppm.

The term “heavy oil” includes bitumen, as well as lighter materials thatmay be found in a sand or carbonate reservoir. “Heavy oil” includes oilsthat are classified by the American Petroleum Institute (API), as heavyoils, extra heavy oils, or bitumens. Thus the term “heavy oil” includesbitumen. Heavy oil may have a viscosity of about 1000 centipoise (cP) ormore, 10,000 cP or more, 100,000 cP or more or 1,000,000 cP or more. Ingeneral, a heavy oil has an API gravity between 22.3° API (density of920 kilograms per meter cubed (kg/m³) or 0.920 grams per centimetercubed (g/cm³)) and 10.0° API (density of 1,000 kg/m³ or 1 g/cm³). Anextra heavy oil, in general, has an API gravity of less than 10.0° API(density greater than 1,000 kg/m³ or greater than 1 g/cm³). For example,a source of heavy oil includes oil sand or bituminous sand, which is acombination of clay, sand, water, and bitumen. The recovery of heavyoils is based on the viscosity decrease of fluids with increasingtemperature and/or solvent concentration. Once the viscosity is reduced,the mobilization of fluids by steam, hot water flooding, or gravity ispossible. The reduced viscosity makes the drainage quicker and thereforedirectly contributes to the recovery rate. A heavy oil may include heavyend components and light end components.

The term “asphaltenes” or “asphaltene content” refers to pentaneinsolubles (or the amount of pentane insoluble in a sample) according toASTM D3279. Other examples of standard ASTM asphaltene tests includeASTM test numbers D4055, D6560, and D7061.

“Heavy end components” in heavy oil may comprise a heavy viscous liquidor solid made up of heavy hydrocarbon molecules. Examples of heavyhydrocarbon molecules include, but are not limited to, molecules havinggreater than or equal to 30 carbon atoms (C₃₀+). The amount of moleculesin the heavy hydrocarbon molecules may include any number within orbounded by the preceding range. The heavy viscous liquid or solid may becomposed of molecules that, when separated from the heavy oil, have ahigher density and viscosity than a density and viscosity of the heavyoil containing both heavy end components and light end components. Forexample, in Athabasca bitumen, about 70 weight (wt.) % of the bitumencontains C₃₀+ molecules with about 18 wt. % of the Athabasca bitumenbeing classified as asphaltenes. The heavy end components may includeasphaltenes in the form of solids or viscous liquids.

“Light end components” in heavy oil may comprise those components in theheavy oil that have a lighter molecular weight than heavy endcomponents. The light end components may include what can be consideredto be medium end components. Examples of light end components and mediumend components include, but are not limited to, light and mediumhydrocarbon molecules having greater than or equal to 1 carbon atom andless than 30 carbon atoms. The amount of molecules in the light andmedium end components may include any number within or bounded by thepreceding range. The light end components and medium end components maybe composed of molecules that have a lower density and viscosity than adensity and viscosity of heavy end components from the heavy oil.

A “fluid” includes a gas or a liquid and may include, for example, aproduced or native reservoir hydrocarbon, an injected mobilizing fluid,hot or cold water, or a mixture of these among other materials. “Vapor”refers to the gas phase which may contain various materials. Vapor mayconsist of solvent in the gas form, steam, wet steam, and mixtures ofsteam and wet steam, any of which could possibly be used with a solventand other substances, and any material in the vapor phase.

“Facility” or “surface facility” is a tangible piece of physicalequipment through which hydrocarbon fluids are either produced from asubterranean reservoir or injected into a subterranean reservoir, orequipment that can be used to control production or completionoperations. In its broadest sense, the term facility is applied to anyequipment that may be present along the flow path between a subterraneanreservoir and its delivery outlets. Facilities may comprise productionwells, injection wells, well tubulars, wellbore head equipment,gathering lines, manifolds, pumps, compressors, separators, surface flowlines, steam generation plants, solvent vaporizers, processing plants,and delivery outlets. In some instances, the term “surface facility” isused to distinguish from those facilities other than wells.

“Pressure” is the force exerted per unit area on the walls of a volume.Pressure may be shown in this disclosure as pounds per square inch(psi), kilopascals (kPa) or megapascals (MPa). “Atmospheric pressure”refers to the local pressure of the air. “Absolute pressure” (psia)refers to the sum of the atmospheric pressure (14.7 psia at standardconditions) plus the gauge pressure. “Gauge pressure” (psig) refers tothe pressure measured by a gauge, which indicates only the pressureexceeding the local atmospheric pressure (i.e., a gauge pressure of 0psig corresponds to an absolute pressure of 14.7 psia). The term “vaporpressure” has the usual thermodynamic meaning. For a pure component inan enclosed system at a given pressure, the component vapor pressure isessentially equal to the total pressure in the system. Unless otherwisespecified, the pressures in the present disclosure are absolutepressures.

A “subterranean reservoir” (or “subterranean formation”) is a subsurfacerock, for example carbonate or sand reservoir, from which a productionfluid, or resource, can be harvested. A subterranean reservoir mayinterchangeably be referred to as a subterranean formation. Thesubterranean formation may include sand, granite, silica, carbonates,clays, and organic matter, such as bitumen, heavy oil (e.g., bitumen),oil, gas, or coal, among others. Subterranean reservoirs can vary inthickness from less than one foot (0.3048 meters (m)) to hundreds offeet (hundreds of meters). The resource is generally a hydrocarbon, suchas a heavy oil impregnated into a sand bed.

A “thermal extraction process” (or “thermal recovery process”) includesany type of hydrocarbon extraction process that uses a heat source toenhance the extraction/recovery of heavy oils, including bitumen, from asubterranean reservoir or formation, for example, by lowering theviscosity of a hydrocarbon. The processes may use injected mobilizingfluids, such as but not limited to hot water, wet steam, dry steam, orsolvents, alone or in any combination, to lower the viscosity of thehydrocarbon. Any of the thermal recovery processes may be used inconcert with solvents. For example, thermal recovery processes mayinclude cyclic steam stimulation (CSS), steam assisted gravity drainage(SAGD), steam flooding, in-situ combustion and other such processes.

A “solvent-based extraction process” (or “solvent-based recoveryprocess”) includes any type of hydrocarbon extraction process that usesa solvent to enhance the extraction/recovery of heavy oils, includingbitumen, from a subterranean reservoir or formation, for example, bydiluting or lowering a viscosity of the hydrocarbon. Solvent-basedrecovery processes may be used in combination with other recoveryprocesses, such as, for example, thermal recovery processes. Insolvent-based recovery processes, a solvent is injected into asubterranean reservoir. The solvent may be heated or unheated prior toinjection, may be a vapor or liquid and may be injected with or withoutsteam. Solvent-based recovery processes may include, but are not limitedto, solvent assisted cyclic steam stimulation (SA-CSS), solvent assistedsteam assisted gravity drainage (SA-SAGD), solvent assisted steam flood(SA-SF), vapor extraction process (VAPEX), thermal variations of VAPEXsuch as heated vapor extraction process (H-VAPEX) and azeotropic heatedvapor extraction process (Azeo-VAPEX), cyclic solvent process (CSP),heated cyclic solvent process (H-CSP), solvent flooding, heated solventflooding, liquid extraction process, heated liquid extraction process,solvent-based extraction recovery process (SEP), thermal solvent-basedextraction recovery processes (TSEP), liquid addition to steam forenhanced recovery (LASER), and any other such recovery process employingsolvents either alone or in combination with steam. A solvent-basedrecovery process may be a thermal recovery process if the solvent isheated prior to injection into the subterranean reservoir. Thesolvent-based recovery process may employ gravity drainage.

Steam to Oil Ratio (“SOR”) is the ratio of a volume of steam (in coldwater equivalents) required to produce a volume of oil. Cumulative SOR(“CSOR”) is the average volume of steam (in cold water equivalents) overthe life of the operation required to produce a volume of oil.Instantaneous (“ISOR”) is the instantaneous rate of steam (in cold waterequivalents) required to produce a volume of oil. SOR, CSOR, and ISORare calculated at standard temperature and pressure (“STP”, 15° C. and100 kPa or 60° F. and 14.696 psi).

Likewise, Solvent to Oil Ratio (“S_(ol)OR”) is the ratio of a volume ofsolvent (in cold liquid equivalents) required to produce a volume ofoil. Cumulative S_(ol)OR (“CS_(ol)OR”) is the average volume of solvent(in cold liquid equivalents) over the life of the operation required toproduce a volume of oil. Instantaneous (“IS_(ol)OR”) is theinstantaneous rate of solvent required to produce a volume of oil.S_(ol)OR, CS_(ol)OR, and IS_(ol)OR are calculated at STP.

“Azeotrope” means the “thermodynamic azeotrope” as described furtherherein.

A “wellbore” is a hole in the subsurface made by drilling or inserting aconduit into the subsurface. A wellbore may have a substantiallycircular cross section or any other cross-sectional shape, such as anoval, a square, a rectangle, a triangle, or other regular or irregularshapes. The term “well,” when referring to an opening in the formationor reservoir, may be used interchangeably with the term “wellbore.”Further, multiple pipes may be inserted into a single wellbore, forexample, as a liner configured to allow flow from an outer chamber to aninner chamber.

“Permeability” is the capacity of a rock structure to transmit fluidsthrough the interconnected pore spaces of the structure. The customaryunit of measurement for permeability is the milliDarcy (mD).

“Reservoir matrix” refers to the solid porous material forming thestructure of the subterranean reservoir. The subterranean reservoir iscomposed of the solid reservoir matrix, typically rock or sand, aroundpore spaces in which resources such as heavy oil may be located. Theporosity of a subterranean reservoir is defined by the percentage ofvolume of void space in the rock or sand reservoir matrix thatpotentially contains resources and water.

A “solvent extraction chamber” is a region of a subterranean reservoircontaining heavy oil that forms around a well that is injecting solventinto the subterranean reservoir. The solvent extraction chamber has atemperature and a pressure that is generally at or close to a totemperature and pressure of the solvent injected into the subterraneanreservoir. The solvent extraction chamber may form when heavy oil has,due to heat from the solvent, dissolution within the solvent,combination with the solvent, and/or the action of gravity, at leastpartially mobilized through the pore spaces of the reservoir matrix. Themobilized heavy oil may be at least partially replaced in the porespaces by solvent, thus forming the solvent chamber. In practice, layersin the subterranean reservoir containing heavy oil may not necessarilyhave pore spaces that contain 100 percent (%) heavy oil and may containonly 70-80 volume (vol.) % heavy oil with the remainder possibly beingwater or gas. A water and/or gas containing layer in the subterraneanreservoir may comprise 100% water and/or gas in the pore spaces, butgenerally contains 5-70 vol. % gas and 20-30 vol. % water with anyremainder possibly being heavy oil.

A “vapor chamber” is a solvent extraction chamber that includes a vapor,or vaporous solvent. Thus, when the solvent is injected into thesubterranean reservoir as a vapor, a vapor chamber may be formed aroundthe well.

A “reservoir chamber” is a region of the subterranean reservoir thatgenerally contains heavy oil and is affected by (such as increased intemperature or modified in pressure) and mobilized by the oil recoveryprocess. It is generally a region near the wells, surrounding the wells,as well as intermediate locations between the wells, especially betweenthe injection wells and production wells that are under fluidcommunication. This not only includes the reservoir matrix wherein theheavy oil is located, but also includes rock and mineral deposits thatmay surround the area but may be affected by the heavy oil recoveryprocess (such as experiencing an increase in temperature). Where solventextraction chamber(s) and/or vapor chamber(s) exist, these are part ofthe overall reservoir chamber.

A “non-condensable gas” or “NCG” is a compound that is in a vapor phaseat reservoir pressure and temperature conditions. The term NCG may beused in this disclosure for the purposes as a shorthand reference to theterm “gas phase dilution agent”.

A “gas phase dilution agent” is an agent, composition or streamcontaining at least some amount, preferably at least 50% by weight inamount, of “non-condensable gas” or “NCG”.

“Produced Bitumen to Retained Solvent ratio” or “PBRS” is the amount ofbitumen (by standard condition liquid volume equivalent) extracted fromthe well or reservoir divided by the amount of unrecovered solvent (bystandard condition liquid volume equivalent) injected into the well orreservoir. It is used to measure the solvent recovery efficiency of asolvent assisted production process or solvent recovery process.

“A late life” or “end of life” phase as it refers to solvent based heavyoil recovery processes herein can include the later stages of heavy oilproduction during such processes, a switch from heavy oil productionmode to a solvent recovery mode during such processes, or a combinationthereof. These generally will not be distinct phases in such processes,but a gradual, or multi-step, shift from the general heavy oilproduction mode of the heavy oil extraction process to a solventrecovery process mode, generally performed near the end of theuseful/economic production cycle of a heavy oil reservoir.

A “hydrocarbon solvent” or “hydrocarbon mixture” as used herein means apure component or near pure component solvent or a mixture of at leasttwo, and more usually, at least three, hydrocarbon compounds having anumber of carbon atoms from the range of C₁ to C₃₀+. A hydrocarbonmixture is often at least hydrocarbons in the range of C₃ to C₁₂ orhigher. For industrial applications, the commercially available solventsare generally are a mixture of hydrocarbon compounds. Commercial gradeethane, propane, butane, LPG, gas condensate, diluents, and naphtha areamong the used hydrocarbon solvent.

The terms “approximately,” “about,” “substantially,” and similar termsare intended to have a broad meaning in harmony with the common andaccepted usage by those of ordinary skill in the art to which thesubject matter of this disclosure pertains. It should be understood bythose of skill in the art who review this disclosure that these termsare intended to allow a description of certain features described andclaimed without restricting the scope of these features to the precisenumeral ranges provided. Accordingly, these terms should be interpretedas indicating that insubstantial or inconsequential modifications oralterations of the subject matter described and are considered to bewithin the scope of the disclosure. These terms when used in referenceto a quantity or amount of a material, or a specific characteristic ofthe material, refer to an amount that is sufficient to provide an effectthat the material or characteristic was intended to provide. The exactdegree of deviation allowable may in some cases depend on the specificcontext.

The articles “the”, “a” and “an” are not necessarily limited to meanonly one, but rather are inclusive and open ended so as to include,optionally, multiple such elements.

As used herein, the phrase “at least one,” in reference to a list of oneor more entities should be understood to mean at least one entityselected from any one or more of the entity in the list of entities, butnot necessarily including at least one of each and every entityspecifically listed within the list of entities and not excluding anycombinations of entities in the list of entities. This definition alsoallows that entities may optionally be present other than the entitiesspecifically identified within the list of entities to which the phrase“at least one” refers, whether related or unrelated to those entitiesspecifically identified. Thus, as a non-limiting example, “at least oneof A and B” (or, equivalently, “at least one of A or B,” or,equivalently “at least one of A and/or B”) may refer, to at least one,optionally including more than one, A, with no B present (and optionallyincluding entities other than B); to at least one, optionally includingmore than one, B, with no A present (and optionally including entitiesother than A); to at least one, optionally including more than one, A,and at least one, optionally including more than one, B (and optionallyincluding other entities). In other words, the phrases “at least one,”“one or more,” and “and/or” are open-ended expressions that are bothconjunctive and disjunctive in operation. For example, each of theexpressions “at least one of A, B and C,” “at least one of A, B, or C,”“one or more of A, B, and C,” “one or more of A, B, or C” and “A, B,and/or C” may mean A alone, B alone, C alone, A and B together, A and Ctogether, B and C together, A, B and C together, and optionally any ofthe above in combination with at least one other entity.

As used herein, the term “and/or” placed between a first entity and asecond entity means one of (1) the first entity, (2) the second entity,and (3) the first entity and the second entity. Multiple entities listedwith “and/or” should be construed in the same manner, i.e., “one ormore” of the entities so conjoined. Other entities may optionally bepresent other than the entities specifically identified by the “and/or”clause, whether related or unrelated to those entities specificallyidentified. Thus, as a non-limiting example, a reference to “A and/orB,” when used in conjunction with open-ended language such as“comprising” may refer to A only (optionally including entities otherthan B); to B only (optionally including entities other than A); to bothA and B (optionally including other entities). These entities may referto elements, actions, structures, steps, operations, values, and thelike.

As used herein the terms “adapted” and “configured” mean that theelement, component, or other subject matter is designed and/or intendedto perform a given function. Thus, the use of the terms “adapted” and“configured” should not be construed to mean that a given element,component, or other subject matter is simply “capable of” performing agiven function but that the element, component, and/or other subjectmatter is specifically selected, created, implemented, utilized,programmed, and/or designed for the purpose of performing the function.It is also within the scope of the present disclosure that elements,components, and/or other recited subject matter that is recited as beingadapted to perform a particular function may additionally oralternatively be described as being configured to perform that function,and vice versa.

As used herein, the phrase, “for example,” the phrase, “as an example,”and/or simply the term “example,” when used with reference to one ormore components, features, details, structures, embodiments, and/ormethods according to the present disclosure, are intended to convey thatthe described component, feature, detail, structure, embodiment, and/ormethod is an illustrative, non-exclusive example of components,features, details, structures, embodiments, and/or methods according tothe present disclosure. Thus, the described component, feature, detail,structure, embodiment, and/or method is not intended to be limiting,required, or exclusive/exhaustive; and other components, features,details, structures, embodiments, and/or methods, including structurallyand/or functionally similar and/or equivalent components, features,details, structures, embodiments, and/or methods, are also within thescope of the present disclosure.

Any of the ranges disclosed may include any number within and/or boundedby the range given.

In the illustrative figures herein, in general, elements that are likelyto be included are illustrated in solid lines, while elements that areoptional are illustrated in dashed lines. However, elements that areshown in solid lines may not be essential. Thus, an element shown insolid lines may be omitted without departing from the scope of thepresent disclosure.

FIGS. 1-10 provide illustrative, non-exclusive examples of systemsaccording to the present disclosure, components of systems, data thatmay be utilized to select a composition of a hydrocarbon solvent mixtureand or a reservoir injection mixture that may be utilized with systems,and/or methods, according to the present disclosure, of operating and/orutilizing systems. Elements that serve a similar, or at leastsubstantially similar, purpose are labeled with like numbers in each ofFIGS. 1-10, and these elements may not be discussed in detail hereinwith reference to each of FIGS. 1-10. Similarly, all elements may not belabeled in each of FIGS. 1-10, but associated reference numerals may beutilized for consistency. Elements, components, and/or features that arediscussed herein with reference to one or more of FIGS. 1-10 may beincluded in and/or utilized with any of FIGS. 1-10 without departingfrom the scope of the present disclosure.

Solvent based heavy oil extraction (or “recovery”) processes can beutilized over conventional non-solvent based heavy oil extractionprocesses (such as steam assisted gravity drainage, or SAGD processes)to improve extraction of heavy oil from a subterranean reservoir.Solvent-based recovery processes may be used in combination with otherrecovery processes, such as, for example, thermal recovery processes,such as SAGD. In solvent-based recovery processes, a solvent is injectedinto a subterranean reservoir. The solvent may be heated or unheatedprior to injection, may be a vapor or liquid and may be injected with orwithout steam. Solvent-based recovery processes may include, but are notlimited to, solvent assisted cyclic steam stimulation (SA-CSS), solventassisted steam assisted gravity drainage (SA-SAGD), solvent assistedsteam flood (SA-SF), vapor extraction process (VAPEX), thermalvariations of VAPEX such as heated vapor extraction process (H-VAPEX)and azeotropic heated vapor extraction process (Azeo-VAPEX), cyclicsolvent process (CSP), heated cyclic solvent process (H-CSP), liquidaddition to steam enhanced recovery (LASER), solvent flooding, heatedsolvent flooding, liquid extraction process, heated liquid extractionprocess, solvent-based extraction recovery process (SEP), thermalsolvent-based extraction recovery processes (TSEP), and any other suchrecovery process employing solvents either alone or in combination withsteam. A solvent-based recovery process may be a thermal recoveryprocess if the solvent is heated prior to injection into thesubterranean reservoir. The solvent-based recovery process may employgravity drainage

In these solvent based recovery processes, a large quantity of solventis retained in the reservoir that is trapped under thermodynamicequilibrium and fluid flow behaviors in the depleted zone under thereservoir conditions. This trapped solvent, at the end of bitumenrecovery, can be a considerable portion of the process cost, oftenamounting to over millions of dollars of trapped/unrecovered solvent.Economical or operational conditions may require the recovery of thissolvent during or at the end of the bitumen recovery. The recovery oftrapped solvent in late life of a reservoir operation, or progressivelyas ultimate recoverable bitumen is approaching in the life of areservoir operation, or when otherwise economically or operationallynecessary, can significantly reduce the process cost and improve theeconomics of solvent based recovery processes. Additional environmentalbenefits may be achieved by reducing the amount of solvent in areservoir after end of life (i.e., shut in).

When considering the general economic values of unrecovered solvents ina typical heavy oil reservoir at near the end of the production phase(i.e., late life) of a solvent based heavy oil recovery process, thevalue of the remaining solvent can amount to millions of dollars ofstranded solvent in the reservoir and can be one of the largest overallcosts in a solvent based heavy oil process. High solvent usage processes(such as VAPEX) may have significantly higher quantities of unrecoveredor unrecoverable solvents during the process and thus at late life.“PBRS”, a measure of economic viability, is the “Produced Bitumen toRetained Solvent” ratio and is the amount of bitumen (by standardcondition volume) from the well or reservoir divided by the amount ofunrecovered solvent (by standard condition volume) from the well orreservoir. In reservoirs undergoing the VAPEX process, near the end ofthe production life of the reservoir, the PBRS depends on many factorssuch as the geometry and geology of the reservoir, the type and geometryof the wells, operating conditions, selection of solvent ratios and/orsolvent concentrations, as well as many other possible factors. However,a significant magnitude of lost potential resources and lost economicsare subject to recovery by improved solvent recovery processes.

In the methods discovered and herein disclosed, recovery of the trappedsolvent can be achieved by changing the phase behavior conditions in thereservoir by introducing a gas phase dilution agent. Preferably, aheating agent may also utilized or otherwise present as stored heat inthe reservoir from solvent-based thermal recovery process to providevaporization energy for stripping of the solvent. Alternatively, the gasphase dilution agent can also serve as a, or the, heating agent as well.The heating agent may be comprised of the non-condensable gas, steam ora combination thereof. The heat stored in the reservoir during asolvent-based thermal heavy oil recovery process may serve as theheating agent as well. In preferred embodiments, the gas phase dilutionagent contains or is substantially comprised of a non-condensable gasunder reservoir pressure and temperature conditions. For simplicitypurposes herein, the gas phase dilution agent (which may also bereferred to as the “dilution/heating agent” or designated as “D/HA”) maybe described as a non-condensable gas or NCG herein.

In the present disclosure, a gas phase dilution agent, preferably anon-condensable gas, and associated processes, methods, andconfigurations are utilized to improve solvent recovery fromsubterranean reservoirs at late life of solvent based heavy oil recoveryprocesses. In the majority of the embodiments herein, the gas phasedilution agent will be utilized, at least in part, to reduce the partialpressure of the liquid phase solvent in the reservoir and thus vaporizethe solvent, or at least a portion of the solvent by the various methodsand configurations disclosed herein. This includes vaporizing at least aportion of the lower boiling point components of the solvent. Inconventional solvent recovery systems, the recovery mode is to recoverthe solvent mainly in the liquid phase, preferably by “pushing” thesolvent, or by evaporating and then condensing the solvent, andrecovering the primarily liquid solvent from the production well. As anexample, a solvent based thermal gravity drainage-based heavy oilrecovery process, for example thermal VAPEX, may switch to steaminjection at the end of the life of the economical production, which isalso known as switching to steam assisted gravity drainage (SAGD). Inthis setup, steam evaporates the liquid phase solvent, which thencondenses at the edge of the chamber and is produced mainly as a liquidphase. In contrast, the methods disclosed herein are designed tovaporize, in-situ, the solvent (or components of solvent) and recoverthe solvent from the reservoir primarily in the vapor phase by injectionand production of gas (preferably a non-condensable gas) as discussedfurther herein. It has been discovered herein, and as will be shown,that recovering the solvent primarily in the vapor phase according tothe methods herein, results in a distinctly improved recovery rate(i.e., solvent recovery percentage) over methods of recovering thesolvent in the liquid phase. For simplicity herein, the term “solvent”as used refers to the solvent which is targeted to be recovered from thereservoir, and includes the previously injected solvent that is to berecovered from the reservoir, or a portion of the components thereofunless otherwise noted.

To simplify the discussions in this disclosure, the term “late life” asit refers to solvent based heavy oil recovery processes herein caninclude the later stages of heavy oil production during such processes,a switch from heavy oil production mode to a solvent recovery modeduring such processes for example due to operational or economicfactors, or a combination thereof. As will be obvious to one of skill inthe art in light of this disclosure, these generally will not bedistinct phases in such processes, but a gradual, or multi-step, shiftfrom the general heavy oil production mode of the heavy oil extractionprocess to a solvent recovery process mode, generally performed near theend of the useful production cycle of a heavy oil reservoir, orotherwise due to other factors such as operational or economicconsiderations.

To help illustrate the present concepts, FIG. 1 illustrates the solventstripping mechanism due to dilution. Introduction of a non-condensablediluting agent into the pore space results in a drop in the solventpartial pressure, thus reducing its molar fraction in the liquid phase.The smaller liquid phase molar fraction implies stripping of the solventfrom the liquid phase into a gas phase. The solvent is thus easier todisplace due to the gas phase mobility. Continuous injection of thediluting agent into the reservoir and production of the solvent vaporresults in the removal of much of the solvent. This is demonstrated onFIG. 1 by the dashed arrows, where the solvent stored during the thermalsolvent-based recovery (shown by the triangles) is reduced to much lowervalues (shown by the circles) at the end of the solvent stripingprocess.

This concept is further illustrated in FIG. 2 which depicts the injectedsolvent content of a reservoir as an example. Here, on the left handside, illustrates the amount of solvent in the reservoir in both theliquid phase (x_(i): the molar fraction of solvent in the liquid phase)and the vapor phase (y_(i): the molar fraction of solvent in the vaporphase), as well as the bitumen in the liquid phase. By adding thenon-condensable gas (NCG) to the reservoir, a greater portion of theliquid solvent vaporizes and increases the solvent concentration in thevapor phase of the reservoir. This vaporized fraction of the solvent canthen be extracted from the reservoir by the various methods describedherein. These methods, as will be shown, result in significantlyincreased amounts of overall solvent recovery, as well as significantlyincreased rates in overall solvent recovery, and are particularlybeneficial for application in late life solvent recovery applications.

Following are specific methods for employing the concept of thisinvention. Most of these methods have been modeled usingstate-of-the-art techniques and shown to produce significant improvementin solvent recovery, both in reduction of time of recovery as well asthe total amount of solvent recovered. While not explicitly illustratedor quantified herein, these methods additionally have the benefit ofsignificantly reducing the overall cost of solvent recovery, as thesemethods require significantly less time for recovery of the solvent(therefore reducing manhours, capital employed, maintenance, etc.), aswell as not requiring the installation or operation of large steamgeneration systems. These methods as described herein, particularlywhere the solvent is substantially recovered in the vapor phase, solventcan more easily be separated from the NCG utilized in the injection andrecovery techniques discussed herein, than is prior art recovery methodssuch as steam injection at late life wherein the solvent is recovered ina liquid phase generally mixed with both water and recovered bitumen.These methods are also very effective in maintaining reservoir pressureduring the solvent recovery and shut-in phases of the reservoir toprevent intrusion or unwanted cross flow from other reservoirs orreservoir chambers in the region. These methods may additionally haveecological benefits, by reducing the amount of water utilized (i.e., byreducing overall steam demand during recovery), reducing the amount ofunrecoverable water (i.e., by reducing the amount of water, from steam,left in the reservoir at the end of the reservoir production/recovery),enhancing solvent recovery percentage, as well as reducing the cost ofsolvent recovery (thereby making the solvent recovery from the reservoireven more feasible).

One embodiment of the present invention is to utilize the NCG injectionrecovery process in a “single well pair” configuration. It should benoted that the term “single well pair” as used herein, is meant to usewhere the primary implementation of this embodiment is to inducerecovery between an injector and a producer in a well pair. This doesnot mean that this method may not be utilized where there is more thanone well pair (or infill wells) in the reservoir or in the vicinity ofthe “single well pair”, but only that the primary mode of the recoveryoperation described in this embodiment is to induce recovery between aninjector and a producer in a well pair as compared to other embodimentsof the methods disclosed herein, where the primary mode of the recoveryoperation in these other embodiments may be to induce recovery betweenor with multiple well pairs (and/or infill wells).

FIG. 3 is a simplistic diagram of a single well pair configuration in asubterranean reservoir (400) which may be utilized to illustrate thecurrent NCG injection recovery process as applied to a single well pairconfiguration. Here, the well pair consists of an injection well (401)and a production well (405).

Generally in a solvent assisted gravity-based drainage process theinjection well will be located at a location above the production wellas shown. It should also be mentioned that the methods herein are notlimited to well pairs that only have a vertical offset component. Inembodiments, the well pair may be staggered (i.e., contain an offsetbetween the two wells in the well pair contains both a lateral, as wellas a vertical, component). The basic operation of the methods herein mayalso apply between pairs that only have a significantly horizontaloffset component. While most of the single well pair and multiple wellpair configurations illustrated herein will show the wells in the wellpairs (i.e., the original injection and production) as significantlyvertically oriented with respect to one another, the principles of theconcepts may additionally apply to these other configurations unlessotherwise noted.

In FIG. 3, the diluting/heating agent (or “D/HA”) containing anon-condensable gas (which, for simplicity purposes in the figures anddescriptions herein, the diluting/heating agent may be referred toalternatively herein as “NCG”) is injected into the reservoir via theinjection well (401). The NCG can be injected at approximately ambientsurface temperature or can be heated prior to injection into thereservoir. Heating the NCG prior to injection can improve the solventrecovery by providing heat for the evaporation of the solvent in thereservoir. In other embodiments, the temperature of the well can beraised prior to, or with, the injection of the NCG into the reservoir.This can be done during normal recovery operations or as part ofpreparation for the solvent recovery stage. In the first case, the NCG,as well as the retained solvent, take advantage of the residual heatstored in the reservoir to improve solvent recovery. In this single wellconfiguration, the NCG and evaporated solvent tend to move upward in thereservoir chamber (410) prior to moving down at the interface of thereservoir chamber towards the production well (405) as illustrated byflow arrows (415). The flow arrows show the path of the NCG andvaporized solvent in the reservoir chamber (410).

State-of-the-art reservoir production modeling was performed to show theimproved solvent recovery rates in conjunction with an embodiment of thepresent invention, as well compare the solvent recovery rates andefficiencies to conventional techniques for solvent recovery utilizingsteam, such as switching to Steam-Assisted Gravity Drainage (SAGD)process near the end of the production life (i.e., late life) of thereservoir. In this modeled comparison, the NCG injection process wasutilized in conjunction with a thermal solvent vapor extraction (VAPEX)process, at “late-life” reservoir conditions. For the comparison models,the reservoir temperature, reservoir pressure and well spacing all weremodeled at the same value. The case shown in FIG. 6A operated a thermalVAPEX process for the heavy oil production period, followed by injectingonly steam for solvent recovery according to the prior art. The caseshown in FIG. 6B operated the same thermal VAPEX process for the heavyoil production period, however, followed by injecting a NCG gasaccording to an embodiment herein. The solvent used in all of the modelsherein was a mixture of essentially C₃-C₉ hydrocarbons which exemplifiesa typical diluent solvent mixture utilized in a solvent-based heavy oilrecovery process (such as thermal VAPEX, or SA-SAGD process). The NCGutilized in all of the models herein was a 50%/50% by mole mixture of C₁(methane) and CO₂ (carbon dioxide) which is exemplary of a productiongas that may be used, readily obtainable, or easily obtainable, inreservoir heavy oil recovery processes. FIGS. 6A and 6B show the solventproduction rates in both liquid and gas phases from the start of solventrecovery stage for the case of single well pair based on single wellpair steam injection (FIG. 6A) and on single well pair NCG injection(FIG. 6B).

The results for the single well pair embodiment are shown in FIGS. 6Aand 6B. In the case of utilizing steam injection for solvent recovery,FIG. 6A, most of the solvent is vaporized by hot steam and moved to theedge of the chamber where it condenses and is then produced as a liquidphase. On the other hand, in the case when using NCG injection forsolvent recovery as shown in FIG. 6B, the processes described hereinallow for some diluting of the gas phase and as a result stripping ofthe solvent into the gas phase, which results in recovery of some of thesolvent in the gas form, and an overall higher solvent recovery. As aresult, there is a significant increase in the overall solvent recoveryrate (i.e., the sum of the “liquid” and “gas” production lines),especially on the front-end of the timeline. This results in not onlyadditional solvent recovered, but more solvent recovered in asignificantly shorter amount of time when utilizing the methods herein.

Even though the present invention is economically beneficial for latelife recovery of solvent in a solvent-based bitumen recovery process(such as VAPEX) in single well pair configuration such as wasexemplified in the models described prior (and results illustrated incomparative FIGS. 6A and 6B), it is seen that the use of the presentinvention in certain multiple well-pair configurations and “sweep”configurations can provide even significantly greater improvements insolvent recovery (as shown in FIG. 6C and FIG. 7 and processes as willbe described further herein). Additionally, the hydrocarbon solvents aregenerally and primarily in vapor form when injected in a thermalsolvent-assisted heavy oil recovery process, for example VAPEX andSA-SAGD. However, the solvent then condenses as it heat up the oil andthe formation, which means that some of it is left behind as a liquidphase. In addition to enhancing solvent recovery at the end of life of aVAPEX process, it will be shown herein that the present invention alsoprovides more significant solvent recovery when utilized for solventrecovery in a reservoir which has utilized an SA-SAGD process duringproduction. In fact, the present invention even eclipses the overallsolvent recovery as compared to when a steam only (SAGD) process isutilized in late life recovery of solvent from solvent-assisted gravitydrainage process.

We start here with a discussion on a few different configurationembodiments of implementations of the present invention to multiple wellpair configurations. It has been discovered that embodiments of thepresent invention can be very effectively used in reservoirs withmultiple wells or multiple well pairs, especially in certain, distinctflow patterns or “modes”. FIGS. 4A, 4B & 4C will be utilized toillustrate these preferred modes using a typical, but non-limiting,example well configurations. In these figures, the subterraneanreservoir or “reservoir” (600) contains a five well pair configurationis shown for purposes of illustration. This may illustrate a typicalreservoir wherein five horizontal well pairs are utilized in asolvent-assisted gravity drainage process (such as VAPEX or SA-SAGD),wherein each well in the well pair run in a substantially horizontaldirection within the subterranean reservoir, and wherein the injectionwell and the production well of each of the well pairs are oriented in asubstantially vertical direction with respect to one another, andfurther wherein the top well is utilized as an injection well and thebottom well used as a production well in each pair. Each of the fivehorizontal well pairs comprises an injection well (601) and a productionwell (605) wherein, in FIGS. 4A-4C (and additionally as in later figuresas will be discussed), these wells are shown in an elevation view, asviewed down the axis of the horizontally running injection andproduction wells (601) and (605).

Starting with the reservoir and well configuration description asillustrated in FIG. 4A, each of the five horizontal well pairs comprisesan injection well (601) and a production well (605). During normaloperation of a solvent-based gravity drainage process, solvent isinjected into the injection well (601). This solvent (as well as othercomponents such as steam) is utilized to reduce the viscosity of theheavy oil (or “bitumen”) that is present in the reservoir (600). Thesolvent and reduced viscosity heavy oil flow in a pattern which formsthe reservoir chamber(s) (610). Here the injected vapor pushes out fromthe injection well (601) and forms the reservoir chamber (610) whereinthe flow is generally outward from injection well (601), wherein thereservoir chamber flow boundaries (615) are illustrated in FIG. 4A. Thecondensed solvent and reduced viscosity heavy oil liquid drainage isthrough the reservoir chamber (610) and the exterior of the liquid flowpattern (620) follows the bottom outer boundaries follow the outercontour of reservoir chamber (610) and is recovered primarily as aliquid from the production well (605). These figure elements shown inFIG. 4A of the operating (or production) portion of the solvent assistedgravity drainage are typically the same for FIGS. 4B and 4C for thepurposes of these illustrations.

In FIGS. 4A, 4B, and 4C, will illustrate different NCG “sweep”configurations of the present invention in late life production/solventrecovery. Starting with FIG. 4A, alternative existing injection wells(the first, third and fifth elements 601 starting from the left in FIG.4A) are converted to, and utilized as “NCG injection wells”, while theintermediate existing injection wells (the second and fourth elements601 starting from the left in FIG. 4A) and all production wells (theelements 605 in FIG. 4A) are converted to, and utilized as“NCG/vaporized solvent and liquid production wells”. In this embodiment,the NCG is injected via the NCG injection wells. As noted prior, the NCGmay comprise any gas that is non-condensable under the reservoirpressure and temperature conditions. The NCG may also be heated prior toinjection to improve solvent recovery. The NCG may also use existingstored heat in the reservoir to obtain an increase in temperature whichimproves solvent recovery. In such embodiment, the reservoir temperatureis raised during the normal thermal production cycle of the reservoir,which increases heavy oil production and in these illustrated late lifecycles, provides additional heating to the injected NCG in the presentsolvent recovery processes. For simplicity purposes in the figures anddescription herein, the diluting/heating agent (or “D/HA”) containing anon-condensable gas may be referred to interchangeably as “NCG”.

Returning to FIG. 4A, in this embodiment, a substantial amount of NCG isinjected into the now converted NCG injection wells. By the term“substantial amount of NCG injected” (or similar) it is meant that avolume or volume rate of NCG is injected into the reservoir sufficientto vaporize at least a portion of the components in the liquid solvent(due to a decrease in partial pressure of the solvent in the vaporphase) thereby decreasing the partial pressure of at least some of thecomponents in the solvent in the vapor phase by at least 5%, at least10%, at least 25%, at least 50%, at least 75%, or more preferably atleast 99%. In preferred embodiments, at least 10 wt %, at least 25 wt %,at least 50 wt %, or more preferably at least 98 wt % of the liquidsolvent in the reservoir is converted to a vapor. After injecting theNCG, at least a portion of the solvent in the reservoir chambers (610)begins to vaporize due to an imposed decrease in the partial pressure ofthe solvent in the reservoir chamber (as used here the term “solvent” isto also include the solvent components, especially the lower boilingpoint solvent components). Instead of condensing and moving down thereservoir chambers as discussed and operated in the production cycle (tobe recovered by the lower located production wells), here, a significantportion of the solvent vaporizes and moves upward through the alternatereservoir chambers (i.e., the chambers now containing the NCG injectionwells). The pressure gradient in the reservoir is maintained such thatthe pressure near the NCG/vaporized solvent production wells is lowerthan the pressure of at least one, and preferably all, of the NCGinjection well(s). This provides a flooding or sweeping effect acrossthe reservoir providing the mechanism to both 1) lower the partialpressure of the solvent in the reservoir chamber(s), thereby convertingat least a portion of the liquid solvent to a vapor, and 2) moving thenow vaporized solvent and NCG across the reservoir from the NCGinjection well(s) to the NCG/vaporized solvent production well forrecovery. This embodiment herein utilizes at least one existingproduction/injection well as a now converted NCG injection well and atleast two existing production/injection wells as a now convertedNCG/vaporized solvent production wells as described above. This createsan NCG/vaporized solvent sweep flow pattern (625) as shown in FIG. 4A.It is noted that the produced NCG with the vaporized solvent from theproduction wells is separated in a surface facility the separated NCG isrecompressed and re heated to a desired temperature if required and isre-injected (recycled) in the NCG injection wells. Any additionallyrequired NCG for solvent recovery process may be added to the recycledNCG stream. The separated solvent from the produced NCG/solvent gas isthe recovered solvent from the gas phase stream. The produced liquidfrom production wells also contain some dissolved NCG, solvent and heavyoil which is treated in the surface facility to separate heavy oil,solvent, and NCG from each other.

FIG. 4B illustrates another embodiment of the NCG sweep technique in awell pattern similar to that in FIGS. 4A & 4C. The elements in FIGS. 4A,4B and 4C are numbered similarly. In FIG. 4B, the reservoir (600)contains a five well pair configuration for purposes of illustration.This may illustrate a typical reservoir wherein five horizontal wellpairs (wherein each well pair is shown in these figures for illustrativepurposes wherein the injector well and the production well are in asubstantially vertical orientation to each other, i.e., “vertical wellpair”, and where each well pair is located in a substantially horizontaldirection relative to at least one adjacent well pair) are utilized in asolvent-assisted gravity drainage process (such as VAPEX or SA-SAGD),wherein the wells of each well pair is oriented in a verticalorientation to one another with the top well utilized as an injectionwell and the bottom well used as a production well in each pair. Each ofthe five horizontal well pairs comprises an injection well (601) and aproduction well (605). During normal operation of a solvent assistedgravity drainage process, solvent is injected into the injection wells(601) similarly to as described in FIG. 4A. This solvent (as well asother components such as steam) is utilized to reduce the viscosity ofthe heavy oil (or “bitumen”) that is present in the reservoir (600). Theproduction process and elements (610) through (620) operate in a similarmanner to as described in FIG. 4A during normal production life of thereservoir under solvent assisted gravity drainage conditions.

In FIG. 4B, an embodiment of the late life production/solvent recoveryNCG sweep configuration is illustrated as follows. In this embodiment,one of the injection wells at one end of the series of wells isconverted to, and utilized as an “NCG/vaporized solvent production well”(shown in FIG. 4B as the first element 601 starting from the left),while the other existing injection wells in a series are converted to,and utilized as “NCG injection wells” (shown in FIG. 4B as the second,third, fourth and fifth elements 601 starting from the left). Also, allof the production wells are converted to liquid production wells (shownin FIG. 4B as 605). In this embodiment, the NCG is injected via the fourNCG injection wells. As noted prior, the NCG may comprise any gas thatis non-condensable under the reservoir pressure and temperatureconditions. The NCG may also be heated prior to injection to improvesolvent recovery. The NCG may also use existing stored heat in thereservoir to obtain an increase in temperature to improve solventrecovery. In such embodiment, the reservoir temperature is raised duringthe normal thermal production cycle of the reservoir, which increasesheavy oil production and in these illustrated late life cycles, providesadditional heating to the injected NCG in the present solvent recoveryprocesses.

Returning to FIG. 4B, in this embodiment, a substantial amount of NCG isinjected into now converted NCG injection wells. After injecting theNCG, at least a portion of the solvent in the reservoir chambers (610)begins to vaporize due to a decrease in the partial pressure of thesolvent in the gas phase (as used here to also include the solventcomponents, especially the lower boiling point solvent components).Instead of condensing and moving down the reservoir chambers asdiscussed in the production cycle (to be recovered by the lower locatedproduction wells), a significant portion of the solvent in the reservoirchambers vaporizes and moves upward through the reservoir chambers whileadditionally moving with a horizontal component direction toward the nowconverted NCG/vaporized solvent production well which is located on oneside of the series of now converted NCG injection wells. This embodimentherein utilizes at least one existing injection well as a now convertedNCG injection well and at least one existing injection well as a nowconverted NCG/vaporized solvent production well as described above. Thiscreates an NCG/vaporized solvent sweep flow pattern (625) as shown inFIG. 4B.

FIG. 4C illustrates another embodiment of the NCG flood technique in awell pattern similar to that in FIGS. 4A & 4B. In FIG. 4C, the reservoir(600) contains, a five well pair configuration for purposes ofillustration. This may illustrate a typical reservoir wherein fivehorizontal well pairs are utilized in a solvent-assisted gravitydrainage process (such as VAPEX or SA-SAGD). Each of the five horizontalwell pairs comprises an injection well (601) and a production well(605). During normal operation of a solvent assisted gravity drainageprocess, solvent is injected into the injection wells (601) similarly toas described in FIG. 4A. This solvent (as well as other components suchas steam) is utilized to reduce the viscosity of the heavy oil (or“bitumen”) that is present in the reservoir (600). The productionprocess and elements (610) through (620) operate in a similar manner toas described in FIG. 4A during normal production life of the reservoirunder solvent assisted gravity drainage conditions.

In FIG. 4C, an embodiment of a late life production/solvent recovery NCGsweep configuration is illustrated as follows. In this embodiment, oneof the existing injection wells at one end of the series of wells isconverted to an “NCG/vaporized solvent production well” (shown in FIG.4C as the third element 601 starting from the left), while the otherexisting injection wells in a series are converted to “NCG injectionwells” (shown in FIG. 4B as the first, second, fourth and fifth elements601 starting from the left). Also all of the production wells areconverted to liquid production wells. In this embodiment, the NCG isinjected via the four NCG injection wells. As noted prior, the NCG maycomprise any gas that is non-condensable under the reservoir pressureand temperature conditions. The NCG may also be heated prior toinjection to improve solvent recovery. The NCG may also use existingstored heat in the reservoir to obtain an increase in temperature toimprove solvent recovery. In such embodiment, the reservoir temperatureis raised during the normal thermal heavy oil production cycle of thereservoir, which increases heavy oil production and in these illustratedlate life cycles, provides additional heating to the injected NCG in thepresent solvent recovery processes.

Returning to FIG. 4C, in this embodiment, a substantial amount of NCG isinjected into now converted NCG injection wells. After injecting theNCG, at least a portion of the solvent in the reservoir chambers (610)begins to vaporize due to a decrease in the partial pressure of thesolvent in the vapor phase (as used here to also include the solventcomponents, especially the lower boiling point solvent components).Instead of condensing and moving down the reservoir chambers asdiscussed in the production cycle (to be recovered by the lower locatedproduction wells), a significant portion of the solvent in the reservoirchambers vaporizes and moves upward through the reservoir chambers whileadditionally moving with a horizontal component direction toward the nowconverted NCG/vaporized solvent production well which is located withinthe series of NCG injection wells (i.e., at least one well paircontaining a NCG injection well is located on each side of the convertedNCG/vaporized solvent production well). Also, any draining liquid isproduced from the production wells that are located in the bottom ofdrainage chamber. This embodiment herein utilizes at least two existingproduction or injection wells as a now converted NCG injection well andat least one existing production or injection well as a now convertedNCG/vaporized solvent production well as described above. This createsan NCG/vaporized solvent sweep flow pattern (625) as shown in FIG. 4C.

It is noted herein that while these embodiments as illustrated in FIGS.4A-4C contemplate utilizing the existing production wells as liquidproduction wells (as well as the data from the models herein are basedon utilizing the existing production wells as liquid production wells),in embodiments of the inter-well pair (or multi-well pair) processesherein, some, or all of the production wells may be converted toNCG/vaporized solvent production wells or NCG injection wells.

The results for the inter-well pair NCG flood case of the presentinvention, as shown in FIG. 6C, the dilution and stripping once againtake place, but now the gas phase sweeps the reservoir area between twochambers and allows for more effective stripping of the solvent into thegas and more effective and faster sweeping of solvent in gas and liquidphases to the production wells. As can be seen comparing the resultsfrom FIGS. 6A, 6B and 6C, there is a significant increase in the overallsolvent recovery rate (i.e., the sum of the “liquid” and “gas”production lines) over the base case steam injection recovery (shown inFIG. 6A), especially on the front-end of the timeline for theembodiments of both the single well pair NCG injection process (resultsshown in FIG. 6B), as well as the inter-well pair NCG flood process(results shown in FIG. 6C) of the present invention. This results in notonly additional solvent recovered, but more solvent recovered in asignificantly shorter amount of time when utilizing the methods herein.It can also be seen that the Solvent Production Rate of the inter-wellpair NCG flood process (FIG. 6C) of the present invention showssignificant recovery results over the single well NCG injectionembodiment (FIG. 6B).

FIG. 7 shown the total Solvent Recovery, for all three (3) casesdescribed in FIGS. 6A-6C. As can be seen from FIG. 7, the processemploying the NCG injection embodiment of the invention as well as theinter-well pair NCG flood embodiment recovered more solvent than thesteam injection (SAGD) case in the early days, even though the SAGD casedid ultimately recover slightly more overall solvent than the NCGinjection embodiment. However, what is taken away here is that theprocess according to the present invention, the NCG injection was ableto ultimately recover nearly as much (or more) solvent from thereservoir as the conventional steam injection case (SAGD) Consideringthe high cost associated with steam generation, water treatment, andother limitations of the steam only case as discussed before, thiscomparable final solvent recovery easily economically justifies theadditional NCG production and injection costs for implementing themethods of the present invention over the steam only late life process(SAGD). The SAGD process, as discussed prior, requires significantlyadditional capital equipment and energy costs, mainly due to the SAGD'sprocess requirement to install and operate substantial onsite steamgeneration facilities, which are not already existing in solventassisted heavy oil recovery operations. This makes the present inventionsignificantly more desirable than conventional SAGD processes when allof the costs in implementing the processes are factored in.

In the NCG injection case of the present invention, only NCG isrequired, no steam is required even as a heating agent, as the heatstored in the reservoir is sufficient to maintain the process of liquidsolvent stripping into the injected diluting agent. Even if some steammay be added to the process, mainly if heating is required, the amountof steam used would be only a small fraction of what would be requiredfor a steam only (SAGD mode) recovery operation; and existing facilitiesin a solvent assisted heavy oil recovery operation may be sufficient forthese purposes without the need to install and operate additional costlysteam generation facilities. Much of this NCG utilized in the presentmethods may be readily available from site operations, can be obtainedor supplemented by pipelines, or can be utilized NCGs, such as CO₂, in asequestration mode. The NCG may be comprised of C₁, C₂, C₃, N₂, CO₂,natural gas, produced gas, flue gas or any combination thereof. Incontrast, in a solvent-based extraction process, the steam facilitiesrequired to perform the steam only (SAGD) process as modeled are notalready present (at least not in the capacity that they would be in anon-solvent SAGD type operation). In order to perform the SAGDoperation, highly capital intensive, energy intensive and manpowerintensive steam generation facilities must be physically brought to thenear vicinity of the well site and connected to the injection well(s).When these additional costs are factored in between the NCG injectioncase of the present invention and the steam injection (SAGD mode)solvent recovery of the prior art, the NCG injection recovery process ofthe present invention possess significantly improved economics.

This basic embodiment and associated methods can be expanded by usinginfill wells. FIGS. 4D and 4E illustrate these embodiments. The elements(600) through (625) in these two figures are essentially the same asdescribed in FIG. 4A. However, in this embodiment, the use of an infillwell (630), or multiple infill wells (not shown) may be used in thesolvent recovery process. Here, an existing infill well (630) may beutilized or an infill well may be installed specifically to be used inthe solvent recovery methods as disclosed and described herein. Althoughthe infill well as illustrated in FIGS. 4D and 4E is shown located nearthe bottom of the reservoir, it may be installed at any vertical levelwithin the reservoir between two well pairs. In the embodiment shown inFIG. 4D, the existing or installed infill well is utilized as anNCG/vaporized solvent production well for the late life solvent recoveryprocesses herein. Here, the two adjacent existing injection wells (601)are converted to NCG injection wells. Similar as described in priorFIGS. 4A-4C, in this embodiment, a substantial amount of NCG is injectedinto now converted NCG injection wells. After injecting the NCG, atleast a portion of the solvent in the reservoir chambers (610) begins tovaporize due to a decrease in the partial pressure of the solvent in thevapor phase (as used here “solvent” to also include the solventcomponents, especially the lower boiling point solvent components).Instead of condensing and moving down the reservoir chambers asdiscussed in the production cycle (to be recovered by the lower locatedproduction wells), a significant portion of the solvent in the reservoirchambers vaporizes and moves upward through the reservoir chambers whileadditionally moving with a horizontal component direction toward theinfill well (630) which has been installed as, or has been converted toa NCG/vaporized solvent production well. The majority of the NCG andrecovered vaporized solvent are recovered through the now NCG/vaporizedsolvent production well (prior infill well) and the existing productionwells (605) continue to produce mainly liquid solvent recovery as wellas additional heavy oil (bitumen). This embodiment herein utilizes atleast two existing production injection wells as a now converted NCGinjection wells and an infill well as an NCG/vaporized solventproduction wells as described above. This creates an NCG/vaporizedsolvent sweep flow pattern (625) as shown in FIG. 4D. It is herein notedin the embodiments described herein that the NCG/vaporized solventproduction well(s) may also recover liquid phase solvent from thesubterranean reservoir. Alternatively, in embodiments, one or more ofthe existing production wells (605) can be converted to an NCG injectionwell.

FIG. 4E illustrates a similar configuration and method of operation asshown in FIG. 4D, but in this embodiment, a substantial amount of NCG isinjected into the infill well (630) which has been installed as, orconverted into an NCG injection well. The existing injection wells (601)have been converted into NCG/vaporized solvent production wells, whichnow recover the majority of the NCG and recovered vaporized solvent,while the existing to production wells now recover the majority of theliquid solvent as well as heavy oil (bitumen). However, alternatively(not shown), the two adjacent existing production wells (605) can beconverted to NCG/vaporized solvent production wells. This embodimentherein utilizes at least two existing production or injection wells asnow converted NCG/vaporized solvent production wells and at least oneinfill well as an NCG injection well as described above. This creates anNCG/vaporized solvent sweep flow pattern (625) as shown in FIG. 4E.

State-of-the-art reservoir production modeling was performed to show theimproved solvent recovery rates in conjunction with the flood embodimentof the present invention, as well compare the solvent recovery rates andefficiencies to conventional techniques for solvent recovery utilizingsteam, such as in a Steam-Assisted Gravity Drainage (SAGD) process. Inthis modeled comparison, the NCG injection process was utilized inconjunction with a solvent vapor extraction (VAPEX) process, at nearend-of-life (i.e., “late life”) reservoir conditions. For the comparisonmodels, the reservoir temperature, reservoir pressure and well spacingall were modeled at the same value. In this example, the model utilizeda two well pair configuration which basis for the model is simplyillustrated in FIG. 5. Here, an existing injection well (shown as 601 onthe right hand side of FIG. 5) is converted to an NCG injection well,and an existing injection well (shown as 601 on the left hand side ofFIG. 5) is converted to an NCG/vaporized solvent production well.Illustrated here, the existing production wells (shown as 605 on thebottom of FIG. 5) are also converted to liquid production well (solventand as well as heavy oil). The pressure at the NCG injection well isincreased (and/or the pressure at the NCG/vaporized solvent productionwell is decreased) such that the pressure (P₂) at the NCG injection wellas shown in FIG. 5 is greater than the pressure (P₁) at theNCG/vaporized solvent production well. The NCG is injected through thenow converted NCG injection well and NCG and vaporized solvent areproduced by the now converted NCG/vaporized solvent production well.Heavy oil and primarily liquid solvent are additionally produced fromthe production wells (620).

The NCG injection case as shown in FIGS. 6B and 6C were operating athermal VAPEX process, followed by a late life process consisting ofinjecting NCG gas according to an embodiment herein. The solvent used inall of the models was a mixture of essentially C₃-C₉ hydrocarbons whichexemplifies a typical solvent mixture utilized in a solvent-based heavyoil recovery process (such as VAPEX, or SA-SAGD process). The NCGutilized in the models was a 50%/50% by mole mixture of C₁ (methane) andCO₂ (carbon dioxide) which is exemplary of a production gas that may beused, readily obtainable, or easily obtainable, in reservoir heavy oilrecovery processes. The models were run after the reservoir had been inthermal VAPEX service, and FIGS. 6B and 6C show the solvent productionrates from the start of the late life recovery processes describedherein (i.e., start of NCG injection).

As can be seen by comparing FIGS. 6A, 6B and 6C, the process accordingto the invention in the inter-well pair flooding model shows asignificant increase in the solvent recovery in both the gas phase andthe liquid phase over the single well pair steam injection of the priorart, as well as the single well pair NCG injection embodiment of thepresent invention. This NCG flood embodiment, utilizing a flood (or“sweep”) from at least one well pair to at least another well pair inthe reservoir, resulted in significant enhancement in solvent recoveryin both the gas phase and the liquid phase, as well as the total solventrecovery (sum of gas and liquid phase solvent recovery). Additionally,it can be seen that in this multiple well pair embodiment of the presentinvention that there is a significant increase in the overall solventrecovery rate (i.e., the sum of the “liquid” and “gas” productionlines), especially on the front-end of the timeline resulting in a veryshort timeframe required for near full recoverable solvent production.

This results in not only additional solvent recovered, but more solventrecovered in a significantly shorter amount of time when utilizing themethods herein. FIG. 7 further illustrates the significant impact ofusing this embodiment of solvent recovery in a VAPEX process for latelife solvent recovery. In FIG. 7, it can be seen in the inter-well pairNCG flood model of the present invention, that a higher solvent recoverycompared to steam injection case (SAGD mode) and NCG injection in singlewell pair configuration is achieved. Additionally, it can be seen thatthe inter-well pair NCG flood embodiment of the present invention canachieve very high total solvent recovery, and notably, it can also beseen that this recovery plateau is reached in a very short time frame inthe inter-well pair NCG flood case.

While not wishing to be held to any particular theory, as discussedprior, it is believed that significantly more solvent can be achieved byconverting the solvent into a vapor phase and recovering the solvent asa vapor. It is further believed that while steam injection provides heatand vaporize the liquid solvent from depleted chamber, the condensationof the steam and solvent at the edge of the chambers results in solventto be recovered as a draining liquid through only the bottom productionwells which is a slower process. In the present invention both convertedinjection wells, as well as existing production wells can be utilizedfor production, wherein a substantial amount of the existing liquidsolvent that remained in the reservoir is now produced and recovered ina vapor phase. Also, it is believed that in the present invention, asignificant amount of solvent in the reservoir is converted to vapor,leaving a smaller volume of the liquid solvent in the well, which ismuch more difficult to displace and achieve high solvent recovery in theliquid phase. As such, the present invention offers significantimprovements in solvent recovery over the conventional methods in theart.

In another embodiment of the present invention, the solvent recoveryprocesses herein can be utilized in a reservoir containing one or morewells or well pairs preferably under a gas cap. FIG. 8 illustrates thisembodiment in a five well pair arrangement similar to those described inthe production life stages discussed with respect to FIGS. 4A, 4B and4C, wherein the well(s) are operating under a natural or induced gascap. The production process and elements (600) through (620) operate ina similar manner to as described in FIG. 4A during normal productionlife of the reservoir under solvent assisted gravity drainageconditions. In this embodiment, a gas cap may be naturally present, orit may already have been established in the reservoir, or may beestablished as a step in performing the processes as described in thisembodiment. In the cases where the facilities for a gas cap may alreadybe established in the reservoir, facilities for injecting andmaintaining the gas cap may be utilized or modified for the present NCGgas cap expansion description.

In FIG. 8, an embodiment of a late life production/solvent recovery NCGgas cap flood configuration according to the invention herein isillustrated as follows. In this embodiment, during late life production,the existing injection wells (601) are shut in. A stream containing asubstantial amount of NCG is injected into the top of the reservoirthrough injection facilities in fluid communication with the top of thereservoir, such as, and preferably when, gas cap injection facilitiesare already in place during the production phase. As illustrated in FIG.8, an existing gas cap, or newly established gas cap, now containing NCGand vaporized solvent, is expanded via dropping the reservoir pressureor injection of the NCG containing stream and flows in a pattern (630)from the top of the reservoir through the to reservoir chamber(s) to theproduction well(s) (605). NCG, heavy oil, liquid solvent and vaporizedsolvent are recovered via the production well(s) which have beenconverted to NCG/vaporized solvent production well(s) (605). As perprior embodiments, the NCG may comprise any gas that is non-condensableunder the reservoir pressure and temperature conditions. The NCG mayalso be heated prior to injection to improve solvent recovery. The NCGmay also use existing stored heat in the reservoir to obtain an increasein temperature to improve solvent recovery. In such embodiment, thereservoir temperature is raised during the normal thermal heavy oilproduction cycle of the reservoir, which increases heavy oil productionand in these illustrated late life cycles, provides additional heatingto the injected NCG in the present solvent recovery processes.

Returning to FIG. 8, in this embodiment, a substantial amount of NCG isinjected into the reservoir through existing, or newly installed gas capinjectors. These injectors are preferably located at, or near, the topof the reservoir. After injecting the NCG, at least a portion of thesolvent in the reservoir chambers (610) begins to vaporize due to aninduced decrease in the partial pressure of the solvent (as used here toalso include the solvent components, especially the lower boiling pointsolvent components). The gas cap is extended in volume and begins topush downward with the NCG and now vaporized solvent in the reservoirchambers (610). Instead of condensing and moving down the reservoirchambers as discussed in the production cycle (to be recovered by thelower located production wells), some of the solvent begins vaporizingand is expanded/pushed downward towards the production wells which arenow utilized as the NCG/vaporized solvent production well(s) (605). Thisfloods additional liquid solvent and bitumen to NCG/vaporized solventproduction well(s) as well as vaporized solvent and NCG which are alsorecovered from the NCG/vaporized solvent production well(s).Alternatively, or in conjunction with the converted existing productionwell(s) (605), at least one, or all of the existing injection wells(601) may be converted to NCG/vaporized solvent production well(s). Thisembodiment herein utilizes at least one existing injection well or atleast one existing production well as a now converted NCG/vaporizedsolvent production well. This embodiment creates an NCG/vaporizedsolvent gas cap expansion flow pattern (1025) as shown in FIG. 8. Whilethe process and the models for the gas cap expansion are describedherein wherein the existing injection wells (601) are converted toNCG/vaporized solvent production wells and the existing production wells(605) are utilized as liquid production wells (solvent and as well asheavy oil), in alternative embodiments herein, one or more, includingall, of the production wells (605) can be converted to NCG/vaporizedsolvent production wells. In some embodiments of the gas cap expansionprocesses disclosed herein, both the existing injection wells (601) andthe existing production wells (605) can be converted to NCG/vaporizedsolvent production wells.

State-of-the-art reservoir production modeling was performed to show theimproved solvent recovery rates in conjunction with the gas capexpansion embodiment of the present invention, as well as to compare thesolvent recovery rates and efficiencies to conventional techniques forsolvent recovery utilizing steam injection, such as in a Steam-AssistedGravity Drainage (SAGD) process. In this modeled comparison, the NCGinjection process was utilized in conjunction with a solvent vaporextraction (VAPEX) process, at late life (i.e., near end-of-life)reservoir conditions. For the comparison models, the reservoirtemperature, reservoir pressure and well spacing all were modeled at thesame value. In this example, the model utilized a two well pairconfiguration which basis for the model is simply illustrated by usingonly two of the well pairs shown in FIG. 8. Here, the existing injectionwells (shown as 601 in FIG. 8) are shut in, and existing productionwells (shown as 605 in FIG. 8) are converted to an NCG/vaporized solventproduction well. NCG is injected at the top of the reservoir usingexisting facilities, modified facilities, and/or newly installedfacilities to allow the injection of the NCG stream into the top of thereservoir. As the gas cap expands/grows in the reservoir, NCG and nowvaporized solvent is expanded/pushed downwards in the reservoir chambers(610) as shown by the NCG/vaporized solvent gas cap expansion flowpattern (1025) as shown in FIG. 8. Liquid solvent, vaporized solvent,NCG and bitumen are recovered from the NCG/vaporized solvent productionwell(s) (605). For simplicity and consistency, we will refer to therecovery or production wells in this gas cap expansion recoveryembodiment by the term “NCG/vaporized solvent production wells” eventhough these wells, preferably existing production wells, will be usedto recover liquid solvent, vaporized solvent, NCG and bitumen.

As noted, the model was run with a two well pair model and the resultsare shown in FIG. 9. The “Gas Cap Expansion” case was run utilizing NCGas the gas cap injection gas. The gas cap (either naturally occurring orestablished otherwise) was assumed to consist of C₁ hydrocarbon whichmay be considered to exemplify a typical gas cap in heavy oil reservoirsafter the solvent-assisted gravity drainage process and beginning of thelate life solvent recovery process. The solvent used in the model was amixture of essentially C₃-C₉ hydrocarbons which exemplifies a typicalsolvent mixture utilized in a solvent-based heavy oil recovery process(such as VAPEX, or SA-SAGD process). The NCG utilized in the models wasa 50%/50% by mole mixture of C₁ (methane) and CO₂ (carbon dioxide) whichis exemplary of a production gas that may be used, readily obtainable,or easily obtainable, in reservoir heavy oil recovery processes. Theexisting injection wells were modeled as shut in. All products measuredfrom the model were recovered from the two converted NCG/vaporizedsolvent production wells.

FIG. 9 shows the solvent recovery rate (in liquid equivalents) of thesolvent (in both liquid and gas components) for this gas cap expansionmodel. FIG. 9 illustrates the total solvent recovery for this model as afunction of time as compared to the case of the inter-well pair NCGflood. As can be seen from the model results shown in FIG. 9, the gascap expansion embodiment of the present invention resulted in very highsolvent recovery in a very short time. As seen in FIG. 9, the outcome ofgas cap expansion scheme is very favorable, and is similar to theinter-well pair NCG flood case.

While not wishing to be held to any particular theory, as discussedprior, it is believed that even though the majority of the solvent isrecovered in the liquid phase, that significantly more solvent can berecovered, as compared to conventional methods (such as steaminjection/SAGD) due to the vaporization of the solvent, and therebycreating a vapor expansion in the reservoir chambers promoting recoveryof the liquid phase solvent in the NCG/vaporized solvent productionwells. The NCG not only provides a driving expansion/push, but alsopromotes additional expansion of gas in the reservoir chambers byreducing the partial pressure of the solvent in the reservoir chambers,thereby vaporizing a significant portion of the solvent into a gasphase. In contrast, it is believed that SAGD solvent recovery (whichrelies primarily on steam injection/gravity drainage) of the prior artdoes not promote solvent vaporization/expansion. While the steaminjected in SAGD provides some heat to promote solvent vaporization, thecondensation of steam with solvent on the edge of the chamber drives thesolvent to a liquid phase draining to the production well which is aslower solvent recovery process as compared to the present gas capexpansion solvent recovery invention.

These state-of-the-art reservoir production models were also used tocompare the use of the current methods and embodiments for solventrecovery vs. the conventional approach of switching to SAGD methods forsolvent recovery in a late life solvent assisted gravity drainageoperation (such as SA-SAGD or VAPEX processes). Here, similar wellconfigurations as utilized in the examples for the sweep (or “flood”)and gas cap expansion embodiments herein which results are in shown inFIGS. 7 and 9, respectively were compared with taking the same reservoirconfigurations and applying SAGD for late life solvent recovery. Thecomparative results between these embodiments of the invention and thesteam injection/SAGD solvent recovery methods are shown in FIG. 10. Hereit can be seen that both the flood (sweep) configuration and the gas capexpansion configuration of the present invention resulted in verysimilar solvent recovery rate profiles. The same reservoir model, rununder conventional late life steam injected gravity drainage (SAGD)process achieved far less total solvent recovery. Additionally, whilethe conventional SAGD method recovered slightly more total heavy oil(bitumen) from the reservoir, the Produced Bitumen to Retained Solventratio (PBRS) was still low due to the large amount of unrecoveredsolvent left in the reservoir as a result of this method. In significantcontrast, the methods of the present invention were able to surprisinglyachieve very high PBRS, which results in not only significant overallcost savings, but significantly more efficient use of solvents in theoverall production & solvent recovery process of reservoir use andnatural resources management.

In preferred embodiments herein, the solvent may be a single hydrocarboncompound or a mixture of hydrocarbon compounds having a number of carbonatoms in the range of C₁ to C₃₀+. The solvent may have at least onehydrocarbon in the range of C₃ to C₁₂ and this at least one hydrocarbonmay comprise at least 50 wt. % of the solvent. The mixture may havealiphatic, naphthenic, aromatic, and/or olefinic fractions. The solventmay comprise at least at least 50 wt. % of one or more C₃-C₁₂hydrocarbons, at least 50 wt. % of one or more C₄-C₁₀ hydrocarbons, atleast 50 wt. % of one or more C₅-C₉ hydrocarbons, or a natural gascondensate or a crude oil refinery naphtha.

In preferred embodiments, the reservoir operating pressure may be 5-95%of a fracture pressure of the reservoir, or 0.2 to 5 MPa, or 1 to 2.5MPa. Preferably, the reservoir pressure is measured at the injectionwell(s).

In preferred embodiments, the injection temperature of the gas phasedilution agent may be from 10 to 250° C. or 50-150° C. Preferably, thetemperature of the gas phase dilution agent is measured at the injectionwell. In other preferred embodiments, the reservoir temperature may befrom 50 to 250° C. or 75-150° C. Preferably, the reservoir temperatureis measured at the injection well(s).

In preferred embodiments, the solvent recovery process is performed on areservoir that has been subjected to a solvent-assisted gravity drainageprocess, which comprises injecting steam and hydrocarbon solvent mixtureinto the reservoir. In this embodiment, the range of solventconcentration may be 5 to 40% cold liquid equivalent volume in SA-SAGDprocesses or it may be 80 to 100% by volume in H-VAPEX process. In theseprocesses, a steam and hydrocarbon solvent mixture is injected into thesubterranean reservoir in a vapor phase, wherein the hydrocarbon solventvolume fraction in the steam and hydrocarbon solvent mixture is0.01-100% at injection conditions. In Azeo-VAPEX processes, the steamand hydrocarbon solvent mixture is within 30%+/−, 20%+/−, or 10%+/− ofthe azeotropic solvent molar fraction of the steam and the hydrocarbonsolvent as measured at the reservoir operating pressure. Alternatively,the hydrocarbon solvent molar fraction of the combined steam and solventmixture is 70-110%, 70-100%, 80-100%, or 90 to 100% of the azeotropicsolvent molar fraction of the steam and hydrocarbon solvent mixture asmeasured at the injection conditions. Preferably, the injectionconditions should be the temperature and pressure of the subterraneanreservoir at the injection well(s).

EMBODIMENTS

Additional embodiments of the invention herein are as follows:

Embodiment 1

A process for the recovery of a solvent from a subterranean reservoircontaining a solvent and a heavy oil, the process comprising:

-   -   a) recovering a heavy oil from a subterranean reservoir        utilizing a solvent-assisted gravity drainage process wherein a        portion of a solvent from the solvent-assisted gravity drainage        process remains located in the subterranean reservoir;    -   b) injecting a gas phase dilution agent into the subterranean        reservoir;    -   c) contacting at least a portion of the gas phase dilution agent        with the solvent;    -   d) vaporizing at least a portion of the solvent that is in the        liquid phase to produce a vaporized solvent; and    -   e) extracting at least a portion of the gas phase dilution agent        and the vaporized solvent from the subterranean reservoir.

Embodiment 2

The process of embodiment 1, wherein, prior to the injecting of the gasphase dilution agent, the solvent in the subterranean reservoircomprises both the liquid phase and a gas phase.

Embodiment 3

The process of embodiment 2, wherein step e) includes extracting atleast a portion of the liquid phase of the solvent from the subterraneanreservoir.

Embodiment 4

The process of any one of embodiments 1-3, wherein the gas phasedilution agent comprises a non-condensable gas which remains in vaporphase at pressure and temperature of the subterranean reservoir.

Embodiment 5

The process of embodiment 4, wherein the gas phase dilution agentcomprises at least 50 wt % of the non-condensable gas at the operatingpressure and temperature of the subterranean reservoir.

Embodiment 6

The process of any one of embodiments 4-5, wherein the gas phasedilution agent comprises at least 75 wt % of the non-condensable gas atthe pressure and temperature of the subterranean reservoir.

Embodiment 7

The process of any one of embodiments 4-6, wherein the non-condensablegas comprises C₁, C₂, C₃, N₂, CO₂, natural gas, produced gas, flue gasor any combination thereof.

Embodiment 8

The process of embodiment 7, wherein the non-condensable gas comprisesCO₂.

Embodiment 9

The process of any one of embodiments 1-8, wherein the gas phasedilution agent comprises a heating agent, wherein the heating agent isinjected at a temperature greater than the operating temperature of thesubterranean reservoir.

Embodiment 10

The process of embodiment 9, wherein heating agent is comprised of thenon-condensable gas, steam or a combination thereof.

Embodiment 11

The process of embodiment 10, wherein heating agent is thenon-condensable gas.

Embodiment 12

The process of any one of embodiments 1-11, wherein gas phase dilutionagent utilizes existing heat in the reservoir to provide heat ofvaporization to vaporize the liquid solvent.

Embodiment 13

The process of embodiment 12, wherein the existing heat in thesubterranean reservoir is residual heat from the solvent-assistedgravity drainage process.

Embodiment 14

The process of any one of embodiments 1-13, wherein the solvent-assistedgravity drainage process step comprises a well pair located in thesubterranean reservoir, wherein the well pair is comprised of at leastone injection well and at least one production well.

Embodiment 15

The process of embodiment 14, wherein the at least one injection well isconverted to an NCG injection well prior to, or in conjunction with,step b), and injecting the gas phase dilution agent into thesubterranean reservoir via the NCG injection well.

Embodiment 16

The process of any one of embodiments 14-15, wherein the at least oneproduction well is converted to an NCG/vaporized solvent production wellprior to, or in conjunction with, step b), and extracting at least aportion of the gas phase dilution agent and the vaporized solvent fromthe subterranean reservoir via the NCG/vaporized solvent productionwell.

Embodiment 17

The process of embodiment 16, wherein at least a portion of the liquidphase of the solvent is extracted from the subterranean reservoir viathe NCG/vaporized solvent production well.

Embodiment 18

The process of any one of embodiments 1-13, wherein the solvent-assistedgravity drainage process step comprises at least two well pairs locatedin the subterranean reservoir, wherein each well pair is comprised of aninjection well and a production well in step a), prior to, or inconjunction with, step b):

-   -   converting at least one of the injection wells or production        wells to an NCG injection well; and    -   converting at least one of the injection wells or production        wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection well; and at leasta portion of the gas phase dilution agent and the vaporized solvent isextracted from the subterranean reservoir via the NCG/vaporized solventproduction well.

Embodiment 19

The process of embodiment 18, comprising:

-   -   converting at least one of the injection wells to an NCG        injection well;    -   converting at least one of the injection wells to an        NCG/vaporized solvent production well.

Embodiment 20

The process of embodiment 19, wherein at least a portion of the solventand the heavy oil are extracted in a liquid phase from the twoproduction wells.

Embodiment 21

The process of any one of embodiments 1-13, wherein the solvent-assistedgravity drainage process step comprises at least three well pairslocated in the subterranean reservoir, wherein each well pair iscomprised of an injection well and a production well in step a), priorto, or in conjunction with, step b):

-   -   converting at least two of the injection wells to NCG injection        wells; and    -   converting at least one of the injection wells or production        wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection wells; and atleast a portion of the gas phase dilution agent and the vaporizedsolvent is extracted from the subterranean reservoir via theNCG/vaporized solvent production well.

Embodiment 22

The process of embodiment 21, comprising:

-   -   converting at least one of the injection wells to an        NCG/vaporized solvent production well.

Embodiment 23

The process of any one of embodiments 1-13, wherein the solvent-assistedgravity drainage process step comprises at least three well pairslocated in the subterranean reservoir, wherein each well pair iscomprised of an injection well and a production well in step a), priorto, or in conjunction with, step b):

-   -   converting at least one of the injection wells to NCG injection        wells; and    -   converting at least two of the injection wells or production        wells to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection well; and at leasta portion of the gas phase dilution agent and the vaporized solvent isextracted from the subterranean reservoir via the NCG/vaporized solventproduction wells.

Embodiment 24

The process of embodiment 23, comprising:

-   -   converting at least two of the injection wells to an        NCG/vaporized solvent production well.

Embodiment 25

The process of embodiment 22 or 24, wherein at least a portion of thesolvent and the heavy oil are extracted in a liquid phase from the threeproduction wells.

Embodiment 26

The process of any one of embodiments 18-25, wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir, and the injection well and the production well of each of thewell pairs are oriented substantially vertical with respect to oneanother, and wherein the three well pairs are oriented in asubstantially horizontal direction with respect to each other in thesubterranean reservoir.

Embodiment 27

The process of any one of embodiments 18-25, wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir, and the injection well and the production well of each of thewell pairs are oriented with a vertical offset and a horizontal offsetwith respect to one another, and wherein the three well pairs areoriented in a substantially horizontal direction with respect to eachother in the subterranean reservoir.

Embodiment 28

The process of any one of embodiments 1-13, wherein the solvent-assistedgravity drainage process step comprises at least two well pairs locatedin the subterranean reservoir, wherein each well pair is comprised of aninjection well and a production well in step a), prior to, or inconjunction with, step b):

-   -   converting an existing infill well or installing a new infill        well in the subterranean reservoir located in a horizontal        direction between the two well pairs for use as an NCG/vaporized        solvent production well; and    -   converting the two injection wells or the two production wells        to NCG injection wells;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection well; and at leasta portion of the gas phase dilution agent and the vaporized solvent isextracted from the subterranean reservoir via the NCG/vaporized solventproduction well.

Embodiment 29

The process of embodiment 28, comprising:

-   -   converting at least the two injection wells to NCG injection        wells.

Embodiment 30

The process of any one of embodiments 1-13, wherein the solvent-assistedgravity drainage process step comprises at least two well pairs locatedin the subterranean reservoir, wherein each well pair is comprised of aninjection well and a production well in step a), prior to, or inconjunction with, step b):

-   -   converting an existing infill well or installing a new infill        well in the subterranean reservoir located in a horizontal        direction between the two well pairs for use as an NCG injection        well; and    -   converting the two injection wells or the two production wells        to an NCG/vaporized solvent production well;

wherein at least a portion of the gas phase dilution agent is injectedinto the subterranean reservoir via the NCG injection well; and at leasta portion of the gas phase dilution agent and the vaporized solvent isextracted from the subterranean reservoir via the NCG/vaporized solventproduction wells.

Embodiment 31

The process of embodiment 30, comprising:

-   -   converting the two injection wells to NCG/vaporized solvent        production wells.

Embodiment 32

The process of embodiment 29 or 31, wherein at least a portion of theliquid phase of the solvent is extracted from the subterranean reservoirvia the NCG/vaporized solvent production wells.

Embodiment 33

The process of embodiment 29 or 31, wherein at least a portion of thesolvent and the heavy oil are extracted in a liquid phase from the twoproduction wells.

Embodiment 34

The process of any one of embodiments 28-33, wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir, and the injection well and the production well of each of thewell pairs are oriented substantially vertical with respect to oneanother, and wherein the two well pairs are oriented in a substantiallyhorizontal direction with respect to each other in the subterraneanreservoir.

Embodiment 35

The process of any one of embodiments 28-33, wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir, and the injection well and the production well of each of thewell pairs are oriented with a vertical offset and a horizontal offsetwith respect to one another, and wherein the two well pairs are orientedin a substantially horizontal direction with respect to each other inthe subterranean reservoir.

Embodiment 36

The process of any one of embodiments 1-13, wherein the solvent-assistedgravity drainage process step comprises at least one well pair locatedin the subterranean reservoir, wherein each well pair is comprised of aninjection well and a production well in step a), and prior to, or inconjunction with, step b):

-   -   converting at least one of the injection well or the production        well in each well pair to a NCG/vaporized solvent production        well;    -   injecting the gas phase dilution agent into the top of the        subterranean reservoir or into an existing top zone of the        subterranean reservoir;    -   creating a gas cap in the subterranean reservoir comprising the        gas phase dilution agent; and    -   expanding the gas cap downward into the subterranean reservoir        to at least a point wherein gas cap is in contact with the        NCG/vaporized solvent production wells;

wherein in step e), the at least a portion of the gas phase dilutionagent and the vaporized solvent is extracted from the subterraneanreservoir via the NCG/vaporized solvent production well.

Embodiment 37

The process of embodiment 36, comprising at least two well pairs.

Embodiment 38

The process of embodiment 36, comprising at least three well pairs.

Embodiment 39

The process of any one of embodiments 36-38, comprising:

-   -   converting the production well in at least one of the well pairs        to an NCG/vaporized solvent production well.

Embodiment 40

The process of embodiment 39, comprising:

-   -   converting all of the production wells in the well pairs to        NCG/vaporized solvent production wells.

Embodiment 41

The process of any one of embodiments 37-40 wherein at least a portionof the liquid phase of the solvent is extracted from the subterraneanreservoir via the NCG/vaporized solvent production wells.

Embodiment 42

The process of embodiment 36, wherein the at least one injection well isconverted to the NCG/vaporized solvent production well, and at least aportion of the solvent and the heavy oil are extracted in a liquid phasefrom the at least one production well.

Embodiment 43

The process of any one of embodiments 36-42, wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir, and the injection well and the production well of each of thewell pairs are oriented substantially vertical with respect to oneanother, and wherein the well pairs are oriented in a substantiallyhorizontal direction with respect to each other in the subterraneanreservoir.

Embodiment 44

The process of any one of embodiments 36-42, wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir, and the injection well and the production well of each of thewell pairs are oriented with a vertical offset and a horizontal offsetwith respect to one another, and wherein the well pairs are oriented ina substantially horizontal direction with respect to each other in thesubterranean reservoir.

Embodiment 45

The process of any one of embodiments 36-44, wherein the gas capcomprises C₁.

Embodiment 46

The process of any one of embodiments 36-45, wherein the gas phasedilution agent is introduced into the top of the subterranean reservoirutilizing existing gas cap facilities.

Embodiment 47

The process of any one of embodiments 36-45, further comprising priorto, or in conjunction with, step b), installing gas cap facilities foruse to inject the gas phase dilution agent into the top of thesubterranean reservoir.

Embodiment 48

The process of any one of embodiments 36-47, wherein the gas cap isexpanded downward into the subterranean reservoir to at least a pointbelow the NCG/vaporized solvent production wells.

Embodiment 49

The process of any one of embodiments 1-48, wherein the gas phasedilution agent comprises an amount of non-condensable gas sufficient todecrease the partial pressure of at least some of the components of thesolvent in the gas phase by at least 10%.

Embodiment 50

The process of any one of embodiments 1-49, wherein the gas phasedilution agent comprises an amount of non-condensable gas sufficient toconvert at least 25 wt % of the liquid solvent to a vapor phase.

Embodiment 51

The process of any one of embodiments 1-50, wherein the solventcomprises at least 50 wt % of one or more of C₃-C₁₂ hydrocarbons.

Embodiment 52

The process of any one of embodiments 1-51, wherein the solventcomprises an aliphatic fraction, a naphthenic fraction, an aromaticfraction, an olefinic fraction, or a combination thereof.

Embodiment 53

The process of any one of embodiments 1-52, wherein the solventcomprises natural gas condensate or a crude oil refinery naphtha.

Embodiment 54

The process of any one of embodiments 1-53, wherein pressure of thesubterranean reservoir is 0.2 to 5 MPa.

Embodiment 55

The process of any one of embodiments 1-54, wherein the temperature ofthe subterranean reservoir is from 10 to 250° C.

Embodiment 56

The process of any one of embodiments 1-55, wherein the solvent-assistedgravity drainage process is a SA-SAGD, VAPEX, H-VAPEX, Azeo-VAPEXprocess.

Embodiment 57

The process of any one of embodiments 1-56, wherein during thesolvent-assisted gravity drainage process, a steam and the solvent isinjected as a mixture into the subterranean reservoir in a vapor phase,wherein the solvent volume fraction in the steam and solvent mixture is0.01-100% at injection conditions.

Embodiment 58

The process of embodiment 57, wherein during the solvent-assistedgravity drainage process, the solvent molar fraction of the combinedsteam and solvent mixture is 70-110% of the azeotropic solvent molarfraction of the steam and solvent mixture at injection conditions.

Embodiment 59

A system for the recovery of a solvent from a subterranean reservoircontaining a solvent and a heavy oil, the system comprising:

-   -   a subterranean reservoir containing an existing solvent        comprising a liquid phase and a heavy oil;    -   a first injector fluidly connected to the subterranean        reservoir, wherein the injector is located to inject a gas phase        dilution agent into the subterranean reservoir, so as to contact        at least a portion of the gas phase dilution agent with the        existing solvent and vaporize at least a portion of the existing        solvent to produce a vaporized solvent; and    -   a first NCG/vaporized solvent production well located within the        subterranean reservoir and fluidly connected to the first        injector;

wherein the first NCG/vaporized solvent production well is configured torecover a portion of the gas phase dilution agent and a portion of thevaporized solvent.

Embodiment 60

The system of embodiment 59, wherein

-   -   the first injector is an NCG injection well which was previously        configured as a first existing injection well to inject the        existing solvent into the subterranean reservoir, and wherein        the NCG injection well is configured to inject the gas phase        dilution agent into the subterranean reservoir; and    -   the first NCG/vaporized solvent production well which was        previously configured as a first existing production well to        recover the existing solvent and the heavy oil in the liquid        phase from the subterranean reservoir is configured to        additionally recover a portion of the existing solvent in the        liquid phase and a portion of the heavy oil.

Embodiment 61

The system of embodiment 59, comprising at least two well pairs locatedin the subterranean reservoir, wherein

-   -   a first well pair is comprised of the first injector which was        previously configured as a first existing injection well to        inject the existing solvent into the subterranean reservoir and        a first existing production well; and    -   a second well pair is comprised of the first NCG/vaporized        solvent production well, wherein the first NCG/vaporized solvent        production well was previously configured as a second existing        injection well to inject the existing solvent into the        subterranean reservoir or was previously configured as a second        existing production well to recover the existing solvent and the        heavy oil in the liquid phase from the subterranean reservoir.

Embodiment 62

The system of embodiment 59, comprising at least three well pairslocated in the subterranean reservoir, wherein

-   -   a first well pair is comprised of the first injector which was        previously configured as a first existing injection well to        inject the existing solvent into the subterranean reservoir, and        a first existing production well;    -   a second well pair is comprised of a second injector which was        previously configured as a second existing injection well to        inject the existing solvent into the subterranean reservoir        wherein the second injector is an NCG injection well, and        wherein the NCG injection well has been configured to inject the        gas phase dilution agent into the subterranean reservoir, and a        second existing production well; and    -   a third well pair is comprised of the first NCG/vaporized        solvent production well which was previously configured as a        third existing injection well to inject the existing solvent        into the subterranean reservoir or was previously configured as        a third existing production well to recover the existing solvent        and the heavy oil in the liquid phase from the subterranean        reservoir;

wherein each of the wells run in a substantially horizontal directionwithin the subterranean reservoir, and the three well pairs are orientedin a substantially horizontal direction with respect to each other inthe subterranean reservoir and the third well pair is between the firstwell pair and the second well pair in the substantially horizontaldirection.

Embodiment 63

The system of embodiment 59, comprising at least three well pairslocated in the subterranean reservoir, wherein

-   -   a first well pair is comprised of the first injector which was        previously configured as a first existing injection well to        inject the existing solvent into the subterranean reservoir, and        a first existing production well;    -   a second well pair is comprised of the first NCG/vaporized        solvent production well which was previously configured as a        second existing injection well to inject the existing solvent        into the subterranean reservoir or was previously configured as        a second existing production well to recover the existing        solvent and the heavy oil in the liquid phase from the        subterranean reservoir; and    -   a third well pair is comprised of a second NCG/vaporized solvent        production well which was previously configured as a third        existing injection well to inject the existing solvent into the        subterranean reservoir or was previously configured as a third        existing production well to recover the existing solvent and the        heavy oil in the liquid phase from the subterranean reservoir;

wherein each of the wells run in a substantially horizontal directionwithin the subterranean reservoir, and the three well pairs are orientedin a substantially horizontal direction with respect to each other inthe subterranean reservoir and the first well pair is between the secondwell pair and the third well pair in the substantially horizontaldirection.

Embodiment 64

The system of any one of embodiments 61-63, wherein the existinginjection well and the existing production well of each of the wellpairs are oriented substantially vertical with respect to one another.

Embodiment 65

The system of any one of embodiments 61-63, wherein the existinginjection well and the existing production well of each of the wellpairs are oriented with a vertical offset and a horizontal offset withrespect to one another.

Embodiment 66

The system of embodiment 59, comprising at least two well pairs and aninfill well located in the subterranean reservoir, wherein

-   -   a first well pair is comprised of the first injector which was        previously configured as a first existing injection well to        inject the existing solvent into the subterranean reservoir, and        a first existing production well;    -   a second well pair is comprised of a second injector which was        previously configured as a second existing injection well to        inject the existing solvent into the subterranean reservoir        wherein the second injector is an NCG injection well, and        wherein the NCG injection well is configured to inject the gas        phase dilution agent into the subterranean reservoir, and a        second existing production well; and    -   an infill well is utilized as the first NCG/vaporized solvent        production well

wherein each of the wells run in a substantially horizontal directionwithin the subterranean reservoir, and the two well pairs are orientedin a substantially horizontal direction with respect to each other inthe subterranean reservoir and the first NCG/vaporized solventproduction well is located between the first well pair and the secondwell pair in the substantially horizontal direction and is in fluidconnection with both the first injector and the second injector.

Embodiment 67

The system of embodiment 59, comprising at least two well pairs and aninfill well located in the subterranean reservoir, wherein

-   -   a first well pair is comprised of the first NCG/vaporized        solvent production well which was previously configured as a        first existing injection well to inject the existing solvent        into the subterranean reservoir or was previously configured as        a first existing production well to recover the existing solvent        and the heavy oil in the liquid phase from the subterranean        reservoir; and    -   a second well pair is comprised of a second NCG/vaporized        solvent production well which was previously configured as a        second original injection well to inject the existing solvent        into the subterranean reservoir or was previously configured as        a second existing production well to recover the existing        solvent and the heavy oil in the liquid phase from the        subterranean reservoir, wherein the second NCG/vaporized solvent        production well is configured to recover a portion of the gas        phase dilution agent and a portion of the vaporized solvent;

wherein the first injector is an infill well which is utilized as afirst NCG injection well; and

wherein each of the wells run in a substantially horizontal directionwithin the subterranean reservoir, and the two well pairs are orientedin a substantially horizontal direction with respect to each other inthe subterranean reservoir and the first NCG injection well is locatedbetween the first well pair and the second well pair in thesubstantially horizontal direction and is in fluid connection with boththe first NCG/vaporized solvent production well and the secondNCG/vaporized solvent production well.

Embodiment 68

The system of any one of embodiments 66-67, wherein the injection welland the production well of each of the well pairs are orientedsubstantially vertical with respect to one another.

Embodiment 69

The system of any one of embodiments 66-67, wherein the injection welland the production well of each of the well pairs are oriented with avertical offset and a horizontal offset with respect to one another.

Embodiment 70

The system of embodiments 59, wherein

-   -   the first injector is fluidly connected to the top of the        reservoir to provide a gas cap; and    -   the reservoir contains at least one well pair comprising a first        existing injection well and a first existing production well;

wherein the first existing injection well or the first existingproduction well is converted to the first NCG/vaporized solventproduction well which was previously configured as an existing injectionwell to inject the existing solvent into the subterranean reservoir orwhich was previously configured as an existing production well to injectthe existing solvent into the subterranean reservoir.

Embodiment 71

The system of embodiments 70, wherein the subterranean reservoircomprises more than one injector fluidly connected to the top of thereservoir to provide the gas cap; wherein each injector is located toinject a gas phase dilution agent into the subterranean reservoir, so asto contact at least a portion of the gas phase dilution agent with theexisting solvent and vaporize at least a portion of the existing solventto produce a vaporized solvent.

Embodiment 72

The system of any one of embodiments 70-71, wherein the reservoircontains at least two well pairs each comprising an existing injectionwell and an existing production well; wherein each of the existinginjection wells or each of the existing production wells are convertedto the first NCG/vaporized solvent production wells.

Embodiment 73

The system of any one of embodiments 70-72, wherein the reservoircontains at least two well pairs each comprising an existing injectionwell and an existing production well; wherein each of the existinginjection wells are converted to the first NCG/vaporized solventproduction wells.

Embodiment 74

The system of any one of embodiments 70-73, wherein the reservoircontains at least three well pairs each comprising an existing injectionwell and an existing production well; wherein each of the existinginjection wells or each of the existing production wells are convertedto the first NCG/vaporized solvent production wells.

Embodiment 75

The system of any one of embodiments 70-74, wherein the reservoircontains at least two well pairs each comprising an existing injectionwell and an existing production well; wherein each of the existinginjection wells and each of the existing production wells has beenconverted to the first NCG/vaporized solvent production wells.

Embodiment 76

The system of any one of embodiments 70-75, wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir.

Embodiment 77

The system of any one of embodiments 70-76, wherein the existinginjection well and the existing production well of each of the wellpairs are oriented substantially vertical with respect to one another.

Embodiment 78

The system of any one of embodiments 70-76, wherein the existinginjection well and the existing production well of each of the wellpairs are oriented with a vertical offset and a horizontal offset withrespect to one another.

Embodiment 79

The system of any one of embodiments 72-78, wherein the well pairs areoriented in a substantially horizontal direction with respect to eachother in the subterranean reservoir.

Embodiment 80

The system of any one of embodiments 59-79, further comprising a surfacefacility, wherein the surface facility comprises:

-   -   a separation facility, that is fluidly connected to at least the        first NCG/vaporized solvent production well, wherein at least a        portion of the recovered vaporized solvent is separated from the        recovered gas phase dilution agent, forming a separated        vaporized solvent and a separated gas phase dilution agent;    -   a compression facility, that is fluidly connected to the        separation facility, wherein at least a portion of the separated        gas phase dilution agent is compressed to a higher pressure to        form a compressed gas phase dilution agent; and    -   a heating facility, that is fluidly connected to the separation        facility, wherein at least a portion of the compressed gas phase        dilution agent is heated to a higher temperature to form a        heated gas phase dilution agent;

wherein the heating facility is fluidly connected to the first fluidinjector, wherein at least a portion of the heated gas phase dilutionagent is injected into the subterranean reservoir.

Embodiment 81

The system of embodiment 80, wherein the separation facility is furtherconfigured wherein a produced liquid is separated from the recoveredvaporized solvent and the recovered gas phase dilution agent.

Embodiment 82

The system of embodiment 81, wherein:

-   -   the produced liquid is comprised of a dissolved NCG, recovered        liquid solvent, and heavy oil; and    -   the separation facility is further configured to separate the        dissolved NCG, the recovered liquid solvent, and the heavy oil        to form a separated NCG, a separated recovered liquid solvent,        and a separated heavy oil.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed in the present disclosure areapplicable to the oil and gas industry.

It is believed that the following claims particularly point out certaincombinations and subcombinations that are novel and non-obvious. Othercombinations and subcombinations of features, functions, elements and/orproperties may be claimed through amendment of the present claims orpresentation of new claims in this or a related application. Suchamended or new claims, whether different, broader, narrower, or equal inscope to the original claims, are also regarded as included within thesubject matter of the present disclosure.

1. A process for the recovery of a solvent from a subterranean reservoircontaining a solvent and a heavy oil, the process comprising: a)recovering a heavy oil from a subterranean reservoir utilizing asolvent-assisted gravity drainage process wherein a portion of a solventfrom the solvent-assisted gravity drainage process remains located inthe subterranean reservoir; b) injecting a gas phase dilution agent intothe subterranean reservoir; c) contacting at least a portion of the gasphase dilution agent with the solvent; d) vaporizing at least a portionof the solvent that is in the liquid phase to produce a vaporizedsolvent; and e) extracting at least a portion of the gas phase dilutionagent and the vaporized solvent from the subterranean reservoir.
 2. Theprocess of claim 1, wherein, prior to the injecting of the gas phasedilution agent, the solvent in the subterranean reservoir comprises boththe liquid phase and a gas phase.
 3. The process of claim 2, whereinstep e) includes extracting at least a portion of the liquid phase ofthe solvent from the subterranean reservoir.
 4. The process of claim 1,wherein the gas phase dilution agent comprises a non-condensable gaswhich remains in vapor phase at pressure and temperature of thesubterranean reservoir.
 5. The process of claim 4, wherein the gas phasedilution agent comprises at least 50 wt % of the non-condensable gas atthe operating pressure and temperature of the subterranean reservoir. 6.The process of claim 4, wherein the non-condensable gas comprises C₁,C₂, C₃, N₂, CO₂, natural gas, produced gas, flue gas or any combinationthereof.
 7. The process of claim 6, wherein the non-condensable gascomprises CO₂.
 8. The process of claim 1, wherein the gas phase dilutionagent comprises a heating agent, wherein the heating agent is injectedat a temperature greater than the operating temperature of thesubterranean reservoir.
 9. The process of claim 8, wherein heating agentis comprised of the non-condensable gas, steam or a combination thereof.10. The process of claim 9, wherein heating agent is the non-condensablegas.
 11. A system for the recovery of a solvent from a subterraneanreservoir containing a solvent and a heavy oil, the system comprising: asubterranean reservoir containing an existing solvent comprising aliquid phase and a heavy oil; a first injector fluidly connected to thesubterranean reservoir, wherein the injector is located to inject a gasphase dilution agent into the subterranean reservoir, so as to contactat least a portion of the gas phase dilution agent with the existingsolvent and vaporize at least a portion of the existing solvent toproduce a vaporized solvent; and a first NCG/vaporized solventproduction well located within the subterranean reservoir and fluidlyconnected to the first injector; wherein the first NCG/vaporized solventproduction well is configured to recover a portion of the gas phasedilution agent and a portion of the vaporized solvent.
 12. The system ofclaim 11, wherein the first injector is an NCG injection well which waspreviously configured as a first existing injection well to inject theexisting solvent into the subterranean reservoir, and wherein the NCGinjection well is configured to inject the gas phase dilution agent intothe subterranean reservoir; and the first NCG/vaporized solventproduction well which was previously configured as a first existingproduction well to recover the existing solvent and the heavy oil in theliquid phase from the subterranean reservoir is configured toadditionally recover a portion of the existing solvent in the liquidphase and a portion of the heavy oil.
 13. The system of claim 11,comprising at least two well pairs located in the subterraneanreservoir, wherein a first well pair is comprised of the first injectorwhich was previously configured as a first existing injection well toinject the existing solvent into the subterranean reservoir and a firstexisting production well; and a second well pair is comprised of thefirst NCG/vaporized solvent production well, wherein the firstNCG/vaporized solvent production well was previously configured as asecond existing injection well to inject the existing solvent into thesubterranean reservoir or was previously configured as a second existingproduction well to recover the existing solvent and the heavy oil in theliquid phase from the subterranean reservoir.
 14. The system of claim11, comprising at least three well pairs located in the subterraneanreservoir, wherein a first well pair is comprised of the first injectorwhich was previously configured as a first existing injection well toinject the existing solvent into the subterranean reservoir, and a firstexisting production well; a second well pair is comprised of a secondinjector which was previously configured as a second existing injectionwell to inject the existing solvent into the subterranean reservoirwherein the second injector is an NCG injection well, and wherein theNCG injection well has been configured to inject the gas phase dilutionagent into the subterranean reservoir, and a second existing productionwell; and a third well pair is comprised of the first NCG/vaporizedsolvent production well which was previously configured as a thirdexisting injection well to inject the existing solvent into thesubterranean reservoir or was previously configured as a third existingproduction well to recover the existing solvent and the heavy oil in theliquid phase from the subterranean reservoir; wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir, and the three well pairs are oriented in a substantiallyhorizontal direction with respect to each other in the subterraneanreservoir and the third well pair is between the first well pair and thesecond well pair in the substantially horizontal direction.
 15. Thesystem of claim 11, comprising at least three well pairs located in thesubterranean reservoir, wherein a first well pair is comprised of thefirst injector which was previously configured as a first existinginjection well to inject the existing solvent into the subterraneanreservoir, and a first existing production well; a second well pair iscomprised of the first NCG/vaporized solvent production well which waspreviously configured as a second existing injection well to inject theexisting solvent into the subterranean reservoir or was previouslyconfigured as a second existing production well to recover the existingsolvent and the heavy oil in the liquid phase from the subterraneanreservoir; and a third well pair is comprised of a second NCG/vaporizedsolvent production well which was previously configured as a thirdexisting injection well to inject the existing solvent into thesubterranean reservoir or was previously configured as a third existingproduction well to recover the existing solvent and the heavy oil in theliquid phase from the subterranean reservoir; wherein each of the wellsrun in a substantially horizontal direction within the subterraneanreservoir, and the three well pairs are oriented in a substantiallyhorizontal direction with respect to each other in the subterraneanreservoir and the first well pair is between the second well pair andthe third well pair in the substantially horizontal direction.
 16. Thesystem of claim 11, comprising at least two well pairs and an infillwell located in the subterranean reservoir, wherein a first well pair iscomprised of the first injector which was previously configured as afirst existing injection well to inject the existing solvent into thesubterranean reservoir, and a first existing production well; a secondwell pair is comprised of a second injector which was previouslyconfigured as a second existing injection well to inject the existingsolvent into the subterranean reservoir wherein the second injector isan NCG injection well, and wherein the NCG injection well is configuredto inject the gas phase dilution agent into the subterranean reservoir,and a second existing production well; and an infill well is utilized asthe first NCG/vaporized solvent production well wherein each of thewells run in a substantially horizontal direction within thesubterranean reservoir, and the two well pairs are oriented in asubstantially horizontal direction with respect to each other in thesubterranean reservoir and the first NCG/vaporized solvent productionwell is located between the first well pair and the second well pair inthe substantially horizontal direction and is in fluid connection withboth the first injector and the second injector.
 17. The system of claim11, comprising at least two well pairs and an infill well located in thesubterranean reservoir, wherein a first well pair is comprised of thefirst NCG/vaporized solvent production well which was previouslyconfigured as a first existing injection well to inject the existingsolvent into the subterranean reservoir or was previously configured asa first existing production well to recover the existing solvent and theheavy oil in the liquid phase from the subterranean reservoir; and asecond well pair is comprised of a second NCG/vaporized solventproduction well which was previously configured as a second originalinjection well to inject the existing solvent into the subterraneanreservoir or was previously configured as a second existing productionwell to recover the existing solvent and the heavy oil in the liquidphase from the subterranean reservoir, wherein the second NCG/vaporizedsolvent production well is configured to recover a portion of the gasphase dilution agent and a portion of the vaporized solvent; wherein thefirst injector is an infill well which is utilized as a first NCGinjection well; and wherein each of the wells run in a substantiallyhorizontal direction within the subterranean reservoir, and the two wellpairs are oriented in a substantially horizontal direction with respectto each other in the subterranean reservoir and the first NCG injectionwell is located between the first well pair and the second well pair inthe substantially horizontal direction and is in fluid connection withboth the first NCG/vaporized solvent production well and the secondNCG/vaporized solvent production well.
 18. The system of claim 11,wherein the first injector is fluidly connected to the top of thereservoir to provide a gas cap; and the reservoir contains at least onewell pair comprising a first existing injection well and a firstexisting production well; wherein the first existing injection well orthe first existing production well is converted to the firstNCG/vaporized solvent production well which was previously configured asan existing injection well to inject the existing solvent into thesubterranean reservoir or which was previously configured as an existingproduction well to inject the existing solvent into the subterraneanreservoir.
 19. The system of claim 18, wherein the subterraneanreservoir comprises more than one injector fluidly connected to the topof the reservoir to provide the gas cap; wherein each injector islocated to inject a gas phase dilution agent into the subterraneanreservoir, so as to contact at least a portion of the gas phase dilutionagent with the existing solvent and vaporize at least a portion of theexisting solvent to produce a vaporized solvent.
 20. The system of claim11, further comprising a surface facility, wherein the surface facilitycomprises: a separation facility, that is fluidly connected to at leastthe first NCG/vaporized solvent production well, wherein at least aportion of the recovered vaporized solvent is separated from therecovered gas phase dilution agent, forming a separated vaporizedsolvent and a separated gas phase dilution agent; a compressionfacility, that is fluidly connected to the separation facility, whereinat least a portion of the separated gas phase dilution agent iscompressed to a higher pressure to form a compressed gas phase dilutionagent; and a heating facility, that is fluidly connected to theseparation facility, wherein at least a portion of the compressed gasphase dilution agent is heated to a higher temperature to form a heatedgas phase dilution agent; wherein the heating facility is fluidlyconnected to the first fluid injector, wherein at least a portion of theheated gas phase dilution agent is injected into the subterraneanreservoir.